UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form
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| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended , 2023
or
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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number
(Exact name of Registrant as specified in its charter)
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LAWARE | | |
(State or other jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification Number) |
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| (Address of principal executive offices) | | |
Registrant’s telephone number, including area code ()
Securities registered pursuant to Section 12(b) of the Act:
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| Title of Each Class | Trading Symbol(s) | Name of Each Exchange on Which Registered |
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☑ No ☐
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ ☑
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ No ☐
Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). ☑ No ☐
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” - “smaller reporting company” and “emerging growth company” - in Rule 12b-2 of the Exchange Act:
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| | ☑ | | Accelerated filer | ☐ |
| Non-accelerated filer | ☐ | | Smaller reporting company |
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| Emerging Growth Company |
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If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes No ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No ☑
The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $, computed using the outstanding Common Stock and closing market price on June 30, 2023, the last business day of the Registrant’s most recently completed second fiscal quarter.
At January 31, 2024, there were shares of Common Stock outstanding.
HESS CORPORATION
Form 10-K
TABLE OF CONTENTS
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| Item No. | | | | Page |
| | | PART I | | |
| 1 and 2. | | | | |
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| 1A. | | | | |
| 1B. | | | | |
| 1C. | | | | |
| 3. | | | | |
| 4. | | | | |
| | | PART II | | |
| 5. | | | | |
| 6. | | | | |
| 7. | | | | |
| 7A. | | | | |
| 8. | | | | |
| 9. | | | | |
| 9A. | | | | |
| 9B. | | | | |
| 9C. | | | | |
| | | PART III | | |
| 10. | | | | |
| 11. | | | | |
| 12. | | | | |
| 13. | | | | |
| 14. | | | | |
| | | PART IV | | |
| 15. | | | | |
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Unless the context indicates otherwise, references to “Hess”, the “Corporation”, “Registrant”, “we”, “us”, “our” and “its” refer to the consolidated business operations of Hess Corporation and its subsidiaries.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K, including information incorporated by reference herein, contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Words such as “anticipate,” “estimate,” “expect,” “forecast,” “guidance,” “could,” “may,” “should,” “would,” “believe,” “intend,” “project,” “plan,” “predict,” “will,” “target” and similar expressions identify forward-looking statements, which are not historical in nature. Our forward-looking statements may include, without limitation: our future financial and operational results; our business strategy; estimates of our crude oil and natural gas reserves and levels of production; benchmark prices of crude oil, natural gas liquids and natural gas and our associated realized price differentials; our projected budget and capital and exploratory expenditures; expected timing and completion of our development projects; information about sustainability goals and targets and planned social, safety and environmental policies, programs and initiatives; future economic and market conditions in the oil and gas industry; and expected benefits, timing and completion of the proposed merger with Chevron Corporation (Chevron).
Forward-looking statements are based on our current understanding, assessments, estimates and projections of relevant factors and reasonable assumptions about the future. Forward-looking statements are subject to certain known and unknown risks and uncertainties that could cause actual results to differ materially from our historical experience and our current projections or expectations of future results expressed or implied by these forward-looking statements. The following important factors could cause actual results to differ materially from those in our forward-looking statements:
•fluctuations in market prices of crude oil, natural gas liquids and natural gas and competition in the oil and gas exploration and production industry;
•reduced demand for our products, including due to perceptions regarding the oil and gas industry, competing or alternative energy products and political conditions and events;
•potential failures or delays in increasing oil and gas reserves, including as a result of unsuccessful exploration activity, drilling risks and unforeseen reservoir conditions, and in achieving expected production levels;
•changes in tax, property, contract and other laws, regulations and governmental actions applicable to our business, including legislative and regulatory initiatives regarding environmental concerns, such as measures to limit greenhouse gas emissions and flaring, fracking bans as well as restrictions on oil and gas leases;
•operational changes and expenditures due to climate change and sustainability related initiatives;
•disruption or interruption of our operations due to catastrophic and other events, such as accidents, severe weather, geological events, shortages of skilled labor, cyber-attacks, public health measures, or climate change;
•the ability of our contractual counterparties to satisfy their obligations to us, including the operation of joint ventures under which we may not control and exposure to decommissioning liabilities for divested assets in the event the current or future owners are unable to perform;
•unexpected changes in technical requirements for constructing, modifying or operating exploration and production facilities and/or the inability to timely obtain or maintain necessary permits;
•availability and costs of employees and other personnel, drilling rigs, equipment, supplies and other required services;
•any limitations on our access to capital or increase in our cost of capital, including as a result of limitations on investment in oil and gas activities, rising interest rates or negative outcomes within commodity and financial markets;
•liability resulting from environmental obligations and litigation, including heightened risks associated with being a general partner of Hess Midstream LP;
•risks and uncertainties associated with the proposed Merger (as defined herein) with Chevron, including the following:
•the risk that regulatory approvals are not obtained or are obtained subject to conditions that are not anticipated by Chevron and Hess;
•potential delays in consummating the potential transaction, including as a result of regulatory approvals and the request for additional information and documentary material from the Federal Trade Commission;
•Chevron’s ability to integrate Hess’ operations in a successful manner and in the expected time period;
•the possibility that any of the anticipated benefits and projected synergies of the potential transaction will not be realized or will not be realized within the expected time period;
•the occurrence of any event, change or other circumstance that could give rise to the termination of the Merger Agreement (as defined herein);
•risks that the anticipated tax treatment of the potential transaction is not obtained, or other unforeseen or unknown liabilities;
•customer, shareholder, regulatory and other stakeholder approvals and support, or unexpected future capital expenditures;
•potential litigation relating to the potential transaction that could be instituted against Chevron and Hess or their respective directors, and the possibility that the transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events;
•the effect of the announcement, pendency or completion of the potential transaction on the parties’ business relationships and business generally, and the risks that the potential transaction disrupts current plans and operations of Chevron or Hess and potential difficulties in Hess employee retention as a result of the transaction, as well as the risk of disruption of Chevron’s or Hess’ management and business disruption during the pendency of, or following, the potential transaction;
•the receipt of required Chevron board of directors’ authorizations to implement capital allocation strategies, including future dividend payments, and uncertainties as to whether the potential transaction will be consummated on the anticipated timing or at all, or if consummated, will achieve its anticipated economic benefits, including as a result of risks associated with third party contracts containing material consent, anti-assignment, transfer, other provisions that may be related to the potential transaction which are not waived or otherwise satisfactorily resolved, or changes in commodity prices;
•negative effects of the announcement of the transaction, and the pendency or completion of the proposed acquisition on the market price of Chevron’s or Hess’ common stock and/or operating results;
•rating agency actions and Chevron’s and Hess’ ability to access short and long-term debt markets on a timely and affordable basis; and
•other factors described in Item 1A—Risk Factors in this Annual Report on Form 10-K and any additional risks described in our other filings with the Securities and Exchange Commission.
As and when made, we believe that our forward-looking statements are reasonable. However, given these risks and uncertainties, caution should be taken not to place undue reliance on any such forward-looking statements since such statements speak only as of the date when made and there can be no assurance that such forward-looking statements will occur and actual results may differ materially from those contained in any forward-looking statement we make. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether because of new information, future events or otherwise.
Glossary
Throughout this report, the following company or industry specific terms and abbreviations are used:
API – American Petroleum Institute.
ART Registry – Architecture for REDD+ Transactions Registry.
Appraisal well – An exploration well drilled to confirm the results of a discovery well, or a well that is used to determine the boundaries of a productive formation.
Bbl – One stock tank barrel, which is 42 United States gallons liquid volume.
Barrel of oil equivalent or boe – This reflects natural gas reserves converted on the basis of relative energy content of six mcf equals one barrel of oil equivalent (one mcf represents one thousand cubic feet). Barrel of oil equivalence does not necessarily result in price equivalence, as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past.
Boepd – Barrels of oil equivalent per day.
Bopd – Barrels of oil per day.
CGA – Clean Gulf Associates.
Condensate – A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that when produced, is in the liquid phase at surface pressure and temperature.
DD&A – Depreciation, depletion and amortization.
DEI – Diversity, Equity and Inclusion.
Development well – A well drilled within the proved area of an oil and/or natural gas reservoir with the intent of producing oil and/or natural gas from that area of the reservoir.
Dry hole – An exploratory or development well that does not find oil or natural gas in commercial quantities.
EPA – Environmental Protection Agency.
EHS & SR – Environment, health, safety and social responsibility.
Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive by another reservoir.
E&P – Exploration and production.
Field – An area consisting of a single reservoir or multiple reservoirs all grouped or related to the same individual geological structural feature and/or stratigraphic condition.
FPSO – Floating production, storage, and offloading vessel.
Fractionation – A process by which the mixture of natural gas liquids that results from natural gas processing is separated into the NGL components, such as ethane, propane, butane, isobutane, and natural gasoline, prior to their sale to various petrochemical and industrial end users. Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products.
GAAP – Generally accepted accounting principles in the United States.
GHG – Greenhouse gas.
Gross acres – Acreage in which a working interest is held by the Corporation.
Gross well – A well in which a working interest is held by the Corporation.
ICE – Integrity critical equipment.
IEA – International Energy Agency.
JOA – Joint operating agreement.
LTIP – Long Term Incentive Plans.
Mcf – One thousand cubic feet of natural gas.
Mmcfd – One thousand mcf of natural gas per day.
MSRC – Marine Spill Response Corporation.
MTBE – Methyl tertiary butyl ether.
MWCC – Marine Well Containment Company.
Net acreage or Net wells – The sum of the fractional working interests owned by the Corporation in gross acres or gross wells.
NGL or Natural gas liquids – Naturally occurring hydrocarbon substances that are separated and produced by fractionating natural gas, including ethane, butane, isobutane, propane and natural gasoline. NGL do not sell at prices equivalent to crude oil.
NIST CSF – National Institute of Standards and Technology Cybersecurity Framework.
Non-operated – Projects in which the Corporation has a working interest but does not perform the role of Operator.
OPEC – Organization of Petroleum Exporting Countries.
Operator – The entity responsible for conducting and managing exploration, development, and/or production operations for an oil or gas project.
OSHA – Occupational Safety and Health Administration.
OSRL – Oil Spill Response Limited.
Participating interest – Reflects the proportion of exploration and production costs each party will bear as set out in an operating agreement.
Production sharing contract – An agreement between a host government and the owners (or co-owners) of a well or field regarding the percentage of production each party will receive after the parties have recovered a specified amount of capital and operational expenses.
Productive well – A well that is capable of producing hydrocarbons in sufficient quantities to justify commercial exploitation.
Proved properties – Properties with proved reserves.
Proved reserves – In accordance with the Securities and Exchange Commission regulations and practices recognized in the publication of the Society of Petroleum Engineers entitled, “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” those quantities of crude oil and condensate, NGL and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
PSU – Performance Share Units.
REDD+ – Reducing Emissions from Deforestation and Forest Degradation.
ROU – Right-of-use.
SOFR – Secured Overnight Financing Rate.
Unproved properties – Properties with no proved reserves.
VLCC – Very large crude carrier.
Working interest – An interest in an oil and gas property that provides the owner of the interest the right to participate in the drilling for and production of oil and gas on the relevant acreage and requires the owner to pay a share of the costs of drilling and production operations.
WWC – Wild Well Control.
PART I
Items 1 and 2. Business and Properties
Hess Corporation, incorporated in the State of Delaware in 1920, is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname. At the Stabroek Block (Hess 30%), offshore Guyana, we and our partners have discovered a significant resource base and are executing a multi-phased development of the block. We currently have three FPSOs producing, and plan to have six FPSOs with an aggregate expected production capacity of more than 1.2 million gross bopd producing by the end of 2027. The discovered resources to date on the block are expected to underpin the potential for up to ten FPSOs.
Our Midstream operating segment, which includes Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP at December 31, 2023, provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota. See Midstream on page 13. On October 22, 2023, we entered into an Agreement and Plan of Merger (the Merger Agreement) with Chevron and Yankee Merger Sub Inc. (Merger Subsidiary), a direct, wholly-owned subsidiary of Chevron. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Subsidiary will be merged with and into Hess, and Hess will be the surviving corporation in the Merger as a direct, wholly-owned subsidiary of Chevron (such transaction, the Merger). Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. The transaction is expected to close mid-2024, subject to shareholder and regulatory approvals and other closing conditions. See Item 1A. Risk Factors for a discussion of risks related to the Merger.
Exploration and Production
Proved Reserves
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, and exclude escalations based on future conditions. Crude oil prices used in the determination of proved reserves at December 31, 2023 were $78.10 per barrel for West Texas Intermediate (WTI) (2022: $94.13) and $82.51 per barrel for Brent (2022: $97.98). Our total proved developed and undeveloped reserves at December 31 were as follows:
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| Crude Oil & Condensate | | Natural Gas Liquids | | Natural Gas | | Total |
| | 2023 | | 2022 | | 2023 | | 2022 | | 2023 | | 2022 | | 2023 | | 2022 |
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| | (Millions of bbls) | | (Millions of bbls) | | (Millions of mcf) | | (Millions of boe) |
| Developed | | | | | | | | | | | | | | | |
| United States | 265 | | | 277 | | | 173 | | | 156 | | | 656 | | | 648 | | | 547 | | | 541 | |
| Guyana | 201 | | | 116 | | | — | | | — | | | 71 | | | 37 | | | 213 | | | 122 | |
| Malaysia and JDA | 3 | | | 3 | | | — | | | — | | | 288 | | | 304 | | | 51 | | | 54 | |
| | 469 | | | 396 | | | 173 | | | 156 | | | 1,015 | | | 989 | | | 811 | | | 717 | |
| Undeveloped | | | | | | | | | | | | | | | |
| United States | 204 | | | 206 | | | 89 | | | 89 | | | 336 | | | 356 | | | 349 | | | 354 | |
| Guyana | 186 | | | 164 | | | — | | | — | | | 114 | | | 54 | | | 205 | | | 173 | |
| Malaysia and JDA | — | | | — | | | — | | | — | | | 27 | | | 71 | | | 5 | | | 12 | |
| | 390 | | | 370 | | | 89 | | | 89 | | | 477 | | | 481 | | | 559 | | | 539 | |
| Total | | | | | | | | | | | | | | | |
| United States | 469 | | | 483 | | | 262 | | | 245 | | | 992 | | | 1,004 | | | 896 | | | 895 | |
| Guyana | 387 | | | 280 | | | — | | | — | | | 185 | | | 91 | | | 418 | | | 295 | |
| Malaysia and JDA | 3 | | | 3 | | | — | | | — | | | 315 | | | 375 | | | 56 | | | 66 | |
| | 859 | | | 766 | | | 262 | | | 245 | | | 1,492 | | | 1,470 | | | 1,370 | | | 1,256 | |
Proved undeveloped reserves were 41% of our total proved reserves at December 31, 2023 on a boe basis (2022: 43%). Proved reserves held under production sharing contracts totaled 45% of our crude oil reserves and 34% of our natural gas reserves at December 31, 2023 (2022: 37% and 32%, respectively).
For additional information regarding our proved oil and gas reserves, see the Supplementary Oil and Gas Data to the Consolidated Financial Statements presented on pages 92 through 101.
Production
Worldwide crude oil, NGL, and natural gas net production was as follows:
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| | 2023 | | 2022 | | 2021 |
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| Crude oil – Thousands of barrels | |
| United States | | | | | |
| North Dakota | 30,271 | | | 27,238 | | | 29,176 | |
| Offshore | 8,111 | | | 7,995 | | | 10,451 | |
| Total United States | 38,382 | | | 35,233 | | | 39,627 | |
| Guyana | 41,831 | | | 28,526 | | | 10,920 | |
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| Malaysia and JDA | 1,728 | | | 1,393 | | | 1,264 | |
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| Other (a) | — | | | 5,524 | | | 7,791 | |
| Total | 81,941 | | | 70,676 | | | 59,602 | |
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| Natural gas liquids – Thousands of barrels | | | | | |
| United States | | | | | |
| North Dakota | 24,634 | | | 19,488 | | | 17,889 | |
| Offshore | 550 | | | 681 | | | 1,517 | |
| Total United States | 25,184 | | | 20,169 | | | 19,406 | |
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| Natural gas – Thousands of mcf | |
| United States | | | | | |
| North Dakota | 69,781 | | | 56,903 | | | 59,013 | |
| Offshore | 15,565 | | | 16,024 | | | 26,276 | |
| Total United States | 85,346 | | | 72,927 | | | 85,289 | |
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| Malaysia and JDA | 134,404 | | | 131,509 | | | 126,743 | |
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| John B. Hess | | 69 | | Chief Executive Officer and Director Mr. Hess has been Chief Executive Officer of the Corporation since 1995 and employed by the Corporation since 1977. He has over 45 years of experience in the oil and gas industry. | | 1983 |
| Gregory P. Hill | | 62 | | President and Chief Operating Officer Mr. Hill has been Chief Operating Officer since 2014 and President of the Corporation’s worldwide Exploration and Production business since joining the Corporation in January 2009. Prior to joining the Corporation, Mr. Hill spent 25 years at Royal Dutch Shell and its affiliates in a variety of operations, engineering, technical and managerial roles in Asia-Pacific, Europe and the United States. | | 2009 |
| Timothy B. Goodell | | 66 | | Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer Mr. Goodell has been General Counsel of the Corporation since 2009, Corporate Secretary since 2016, Chief Compliance Officer since 2017 and Executive Vice President since 2020. Prior to joining the Corporation in 2009, he was a partner at the law firm of White & Case, LLP where he spent 25 years. | | 2009 |
| John P. Rielly | | 61 | | Executive Vice President and Chief Financial Officer Mr. Rielly has been Chief Financial Officer of the Corporation since 2004 and Executive Vice President since 2020. Mr. Rielly previously served as Vice President and Controller of the Corporation from 2001 to 2004. Prior to joining the Corporation in 2001, he was a Partner at Ernst & Young, LLP where he was employed for 17 years. | | 2002 |
| Richard Lynch | | 66 | | Senior Vice President, Technology and Services Mr. Lynch has been Senior Vice President, Technology and Services of the Corporation since 2018. Mr. Lynch previously was Senior Vice President Global Developments, Drilling and Completions from 2014. Prior to joining the Corporation in 2014, Mr. Lynch spent over 30 years in well delivery and operations, as well as project and asset management, with BP plc and ARCO. | | 2018 |
| Gerbert Schoonman | | 58 | | Senior Vice President, Global Production Mr. Schoonman has been Senior Vice President, Global Production of the Corporation since January 2020. Since joining the Company in 2011, he served in various operational leadership roles, including as Vice President, Production – Asia Pacific, from January 2011 through August 2012; Vice President, Onshore – Bakken from September 2012 through December 2016; and most recently, as Vice President, Offshore since January 2017. Prior to joining the Corporation, he spent 20 years with Royal Dutch Shell where he served in operational and leadership roles. | | 2020 |
| Andrew Slentz | | 62 | | Senior Vice President, Human Resources and Office Management Mr. Slentz has been Senior Vice President, Human Resources of the Corporation since April 2016 and responsible for Office Management since 2018. Prior to joining the Corporation in 2016, Mr. Slentz served as Executive Vice President of Administration and Human Resources at Peabody Energy since 2010. Mr. Slentz has over 30 years in human resources experience at large international public companies. | | 2016 |
| Barbara Lowery-Yilmaz | | 67 | | Senior Vice President and Chief Exploration Officer Ms. Lowery-Yilmaz has been the Senior Vice President, Exploration of the Corporation since 2014 and Chief Exploration Officer since 2020. Ms. Lowery-Yilmaz has over 30 years of oil and gas industry experience in exploration and technology with BP plc and its affiliates including senior leadership roles. | | 2014 |
*All officers referred to herein hold office in accordance with our By-laws until the first meeting of directors in connection with the annual meeting of stockholders of the Corporation and until their successors shall have been duly chosen and qualified. Each of said officers was elected to the office opposite their name on May 17, 2023.
Each of the above officers has been employed by the Corporation or its affiliates in various managerial and executive capacities for more than five years.
Access to Our Reports
We make available free of charge through our website, www.hess.com, our annual report on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. The information on our website, including our sustainability report, is not part of or otherwise incorporated by reference in this report. Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters for the Audit Committee, Compensation and Management Development Committee, Corporate Governance and Nominating Committee and Environmental, Health and Safety Committee of the Board of Directors are available on our website and are also available free of charge upon request to Investor Relations at our principal executive office. We also file with the New York Stock Exchange (NYSE) an annual certification by our Chief Executive Officer regarding our compliance with the NYSE’s corporate governance standards.
Item 1A. Risk Factors
Our business activities and the value of our securities are subject to significant risks, including the risk factors described below. These risk factors could negatively affect our operations, financial condition, liquidity and results of operations, and as a result, holders and purchasers of our securities could lose part or all of their investments. It is possible that additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.
Proposed Chevron Merger Risks
We will be subject to business uncertainties while the Merger is pending, which could adversely affect our businesses. Uncertainty about the effect of the Merger on employees and those that do business with us may have an adverse effect to the Corporation. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, and could cause those that transact with us to seek to change their existing business relationships with us. Employee retention at the Corporation may be challenging during the pendency of the Merger, as employees may experience uncertainty about their roles. In addition, the Merger Agreement restricts us from entering into certain corporate transactions, entering into certain material contracts, making certain changes to our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Chevron, and generally requires us to continue our operations in the ordinary course of business during the pendency of the Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Merger.
We may become subject to lawsuits relating to the Merger, which could adversely affect our business, financial condition and operating results. We and/or our respective directors and officers may become subject to lawsuits relating to the Merger. Such litigation is very common in connection with acquisitions of public companies, regardless of the merits of the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results.
Completion of the Merger is subject to a number of conditions, and if these conditions are not satisfied or waived, the Merger will not be completed. Failure to complete, or significant delays in completing, the Merger could negatively affect the trading prices of our common stock and our future business and financial results. Completion of the Merger is subject to satisfaction or waiver of certain closing conditions, including (i) the receipt of the required approval from our stockholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended applicable to the Merger, (iii) the absence of any order or law prohibiting consummation of the Merger, (iv) the effectiveness of the Registration Statement on Form S-4 to be filed by Chevron pursuant to which the shares of Chevron common stock to be issued in connection with the Merger will be registered with the U.S. Securities and Exchange Commission and (v) the authorization for listing on the New York Stock Exchange of the shares of Chevron common stock to be issued in connection with the Merger. The obligation of each party to consummate the Merger is also conditioned upon the other party having performed in all material respects its obligations under the Merger Agreement and the other party’s representations and warranties in the Merger Agreement being true and correct (subject to certain materiality qualifiers). Additionally, Hess and Chevron have been engaged in discussions with Exxon Mobil Corporation and China National Offshore Oil Corporation regarding a right of first refusal provision in the joint operating agreement for the Stabroek Block. If these discussions do not result in an acceptable resolution and arbitration (if pursued) does not result in a confirmation that such right of first refusal provision is inapplicable to the Merger, then there would be a failure of a closing condition under the Merger Agreement, in which case the Merger would not close. For additional information, please see the section entitled “The Merger-Stabroek JOA” in Chevron’s preliminary registration statement on Form S-4 to be filed on February 26, 2024. The obligation of Hess to consummate the merger is also subject to the receipt of a tax opinion from legal counsel that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended. There can be no assurance that the conditions to the completion of the Merger will be satisfied or waived or that the Merger will be completed.
If the Merger is not completed, or if there are significant delays in completing the Merger, the trading prices of our common stock and our future business and financial results could be negatively affected, and we may be subject to several risks, including the following:
•the requirement that we pay Chevron a termination fee of approximately $1.715 billion under certain circumstances provided in the Merger Agreement;
•negative reactions from the financial markets, including declines in the prices of our common stock due to the fact that current prices may reflect a market assumption that the Merger will be completed;
•having to pay certain significant costs relating to the Merger; and
•the attention of our management will have been diverted to the Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.
The Merger Agreement limits our ability to pursue alternatives to the Merger. The Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the Merger, or may result in a potential competing acquirer of the Corporation proposing to pay a lower per share price to acquire us than
it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our board of directors, entering into discussions with any third party regarding any competing proposal or offer for a competing transaction.
Because the exchange ratio in the Merger Agreement is fixed and because the market price of Chevron common stock will fluctuate prior to the completion of the Merger, our stockholders cannot be sure of the market value of the Chevron common stock they will receive as consideration in the Merger. Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. The exchange ratio of the Merger consideration is fixed, and under the Merger Agreement there will be no adjustment to the Merger consideration for changes in the market price of Chevron common stock or our common stock prior to the completion of the Merger.
If the Merger is completed, there will be a time lapse between the date of signing of the Merger Agreement and the date on which our stockholders who are entitled to receive the Merger consideration actually receive the Merger consideration. The respective market values of Chevron common stock and our common stock have fluctuated and may continue to fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in each company’s business, operations and prospects, commodity prices, regulatory considerations, and the market’s assessment of Chevron’s business and the Merger. Such factors are difficult to predict and in many cases may be beyond the control of Chevron and us. The actual value of the Merger consideration received by our stockholders at the completion of the Merger will depend on the market value of Chevron common stock at that time. This market value may differ, possibly materially, from the market value of Chevron common stock at the time the Merger Agreement was entered into or at any other time.
Shares of Chevron common stock received by our stockholders as a result of the Merger will have different rights from shares of our common stock. Upon completion of the Merger, our stockholders will no longer be stockholders of Hess, and our stockholders who receive the Merger consideration will become Chevron stockholders, and their rights as Chevron stockholders will be governed by the terms of Chevron’s charter and by-laws. There are differences between the current rights of our stockholders and the rights to which such stockholders will be entitled as Chevron stockholders.
Market and Third-Party Risks
Our business and operating results are highly dependent on the market prices of crude oil, NGL and natural gas, which can be very volatile. Our estimated proved reserves, revenue, operating cash flows, operating margins, liquidity, financial condition and future earnings are highly dependent on the benchmark market prices of crude oil, NGL and natural gas, and our associated realized price differentials, which are volatile and influenced by numerous factors beyond our control. The major foreign oil producing countries, including members of OPEC, may exert considerable influence over the supply and price of crude oil and refined petroleum products. Their ability to agree on a common policy on rates of production and other matters may have a significant impact on the oil markets. Other factors include, but are not limited to: worldwide and domestic supplies of and demand for crude oil, NGL and natural gas; political conditions and events (including weather, instability, changes in governments, armed conflict, economic sanctions and outbreaks of infectious diseases, such as COVID-19) around the world and in particular in crude oil or natural gas producing regions; the cost of exploring for, developing and producing crude oil, NGL and natural gas; the price, availability of and demand for alternative fuels or other forms of energy; the effect of energy conservation and environmental protection efforts; and overall economic conditions globally (including inflation, slower growth or recession, higher interest rates, supply chain constraints, and consequences associated with the ongoing invasion of Ukraine by Russia or the conflict between Israel and Hamas). The sentiment of commodities trading markets as well as other supply and demand factors may also influence the selling prices of crude oil, NGL and natural gas. Average benchmark prices for 2023 were $77.60 per barrel for WTI (2022: $94.33; 2021: $68.08) and $82.18 per barrel for Brent (2022: $99.04; 2021: $70.95). In order to manage the potential volatility of cash flows and credit requirements, we maintain significant bank credit facilities. An inability to access, renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity. Furthermore, from time to time we have entered into, and may in the future enter into or modify, commodity price hedging arrangements to manage commodity price volatility. These arrangements may limit potential upside from commodity price increases, or expose us to additional risks, such as counterparty credit risk, which could adversely impact our cash flow, liquidity or financial condition.
We do not always control decisions made under joint operating agreements and the parties under such agreements may fail to meet their obligations. We conduct many of our E&P operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are not operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with ours, and therefore decisions may be made which are not what we believe is in our best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. For example, in June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood Energy LLC which includes transferring abandonment obligations of Fieldwood to us and other predecessors in title of certain of its assets, who are jointly and severally liable for the obligations. See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements. As a result, actions of our contractual counterparties may adversely affect the value of our investments and result in increased costs or liabilities.
Our industry is highly competitive and many of our competitors are larger and have greater resources and more diverse portfolios than we have. The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies, including acquiring rights to explore for crude oil and natural gas. To a lesser extent, we are also in competition with producers of alternative fuels or other forms of energy, including wind, solar and electric power, and in the future, could face increasing competition due to the development and adoption of new technologies. Many competitors, including national oil companies, are larger and have substantially greater resources to acquire and develop oil and gas assets, or may have established strategic relationships in areas we operate, or may be willing to incur a higher level of risk than we are willing to incur. In addition, competition for drilling services, technical expertise and equipment may affect the availability of technical personnel and drilling rigs, resulting in increased capital and operating costs. Many of our competitors have a more diverse portfolio of assets, which may minimize the impact of adverse events occurring at any one location.
Operational and Strategic Risks
If we fail to successfully increase our reserves, our future crude oil and natural gas production will be adversely impacted. We own or have access to a finite amount of oil and gas reserves, which will be depleted over time. Replacement of oil and gas production and reserves, including proved undeveloped reserves, is subject to successful exploration drilling, development activities, and enhanced recovery programs. Therefore, future oil and gas production is dependent on technical success in finding and developing additional hydrocarbon reserves. Exploration activity involves the interpretation of seismic and other geological and geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons. Drilling risks include unexpected adverse conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions. Future developments may be affected by unforeseen reservoir conditions, which negatively affect recovery factors or flow rates. Similar risks may be encountered in the production of oil and gas on properties acquired from others. In addition, replacing reserves and developing future production are also influenced by the price of crude oil and natural gas and costs of drilling and development activities. Lower crude oil and natural gas prices may reduce capital available for our exploration and development activities, render certain development projects uneconomic or delay their completion, and result in negative revisions to existing reserves while increasing drilling and development costs could negatively affect expected economic returns.
There are inherent uncertainties in estimating quantities of proved reserves and discounted future net cash flows, and actual quantities may be lower than estimated. Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities of our proved reserves and the related future net revenues. In addition, reserve estimates may be subject to downward or upward changes based on production performance, purchases or sales of properties, results of future development, changes in prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas prices increase, and other factors.
Catastrophic and other events, whether naturally occurring or man-made, may materially affect our operations and financial condition. Our oil and gas operations are subject to numerous risks and hazards inherent to operating in the crude oil and natural gas industry, including catastrophic events, which may damage or destroy assets, interrupt operations, result in personal injury and have other significant adverse effects. These events include unexpected drilling conditions, pressure conditions or irregularities in reservoir formations, equipment malfunctions or failures, derailments, fires, explosions, blowouts, oil releases, power outages, cratering, pipeline interruptions and ruptures, severe weather, such as hurricanes, floods, freezes and heat waves or droughts, geological events, shortages in availability of skilled labor, cyber-attacks or health measures related to outbreaks of infectious diseases, such as COVID-19. We maintain insurance coverage against many, but not all, potential losses and liabilities in amounts we deem prudent, including for property and casualty losses. Some forms of insurance may be unavailable in the future or be available only on terms that are deemed economically unacceptable. Moreover, there can be no assurance that such insurance will adequately protect us against liability from all potential consequences and damages. For example, we are self-insured against physical damage to property and liability related to windstorms. In 2023 and 2022, there was no significant hurricane-related downtime whereas in 2021, hurricane related downtime reduced net production by 4,000 boepd and hurricane related maintenance and repair costs were approximately $7 million. In addition, the frequency and severity of weather conditions and other meteorological phenomena, including storms, droughts, extreme temperatures, and changes in temperature and precipitation patterns that impact our business activities, may also be impacted by the effects of climate change. Energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate change. Increased energy use due to weather changes may require us to invest in order to serve increased demand or create operational challenges. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. To the extent the frequency of extreme weather events increases, this could adversely impact our business, results of operations and financial condition.
Significant time delays between the estimated and actual occurrence of critical events associated with development projects may result in material negative economic consequences. As part of our business, we are involved in large development projects, the completion of which may be delayed beyond what was originally planned. Such examples include, but are not limited to, delays in receiving necessary approvals from project members or regulatory or other government agencies, timely access to necessary equipment, services or resources, availability of necessary personnel, construction delays, unfavorable weather conditions, equipment
failures, and outbreaks of infectious diseases, such as COVID-19. These delays could impact our future results of operations and cash flows.
An inability to secure personnel, drilling rigs, equipment, supplies and other required services or to retain key employees may result in material negative economic consequences. We are dependent on oilfield service companies for items including drilling rigs, equipment, supplies and skilled labor. The availability and cost of drilling rigs, equipment, supplies and skilled labor will fluctuate over time given the cyclical nature of the E&P industry. Concerns over global economic conditions, inflation, supply chain disruptions, labor shortages, and other factors, each of which are beyond our control, contribute to increased economic uncertainty for us and our suppliers. As a result, we may encounter difficulties in obtaining required services or could face an increase in cost, which may impact our ability to run our operations and deliver projects on time with the potential for material negative economic consequences. In addition, difficulty in recruiting and retaining adequate numbers of experienced technical personnel could negatively impact our ability to deliver on our strategic goals. Our future success also depends upon the continued service of key members of our senior management team, who play an important role in developing and implementing our strategy. An inability to recruit and retain adequate numbers of experienced technical and professional personnel in the necessary locations or the loss or departure of key members of senior management may prevent us from executing our strategy in full or in part, which could negatively impact our business.
Disruption, failure or cybersecurity attacks affecting or targeting information technology and infrastructure used by the Corporation or our business partners may materially impact our business and operations. Computers and telecommunication systems are an integral part of our exploration, development and production activities and the activities of our business partners. We rely on computer systems, hardware, software, technology infrastructure and online sites and networks for both internal and external operations that are critical to our business (collectively, Digital Systems). Some of our Digital Systems are managed and owned by us, but we rely on third parties for a range of Digital Systems and related products and services, including but not limited to cloud computing services. We use these Digital Systems to communicate, analyze and store proprietary, financial and operating data as well as data about employees, business partners and other third parties (collectively, Confidential Information). Our reliance on technology has increased due to our use of remote communications and hybrid work-from-home arrangements, which increase cybersecurity risks due to the challenges associated with managing remote computing assets and security vulnerabilities that are present in many non-corporate and home networks.
Technical system flaws, power loss and cybersecurity risks, including cyber or phishing-attacks, unauthorized access, malicious software, data privacy breaches by employees or others with authorized access, ransomware, and other cybersecurity issues, could compromise our Digital Systems or those of our business partners and result in disruptions to our business operations or the access, disclosure or loss of our Confidential Information and communications. In addition, computers control oil and gas production, processing equipment, and distribution systems globally and are necessary to deliver our production to market. A disruption, failure or a cyber breach of these operating systems, or of the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets, and make it difficult or impossible to accurately account for production and settle transactions. As a result, any such disruption, failure or cyber breach and any resulting investigation or remediation costs, reputational harm, litigation or regulatory action could have a material adverse impact on our cash flows and results of operations, reputation and competitiveness.
We routinely experience attempts by external parties to penetrate and attack our Digital Systems. Although such attempts to date have not resulted in any material breaches, disruptions, financial loss, or loss of business-critical information, our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient in the future. Threat actors are becoming increasingly adept in using techniques and tools, including artificial intelligence, that circumvent security controls, evade detection and remove forensic evidence. As technologies evolve and these cybersecurity attacks become more sophisticated, we may incur significant costs to upgrade or enhance our security measures to protect against such attacks. We may also face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.
Financial Risks
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms. The exploration, development and production of crude oil and natural gas involve substantial costs, which may not be fully funded from operations. All three major credit rating agencies that rate our debt have assigned an investment grade rating. Although currently we do not have any borrowings under our long-term credit facility, a ratings downgrade, rising interest rates, continued weakness in the oil and gas industry or negative outcomes within commodity and financial markets could adversely impact our access to capital markets by increasing the costs of financing, or by impacting our ability to obtain financing on satisfactory terms. In addition, a ratings downgrade may require that we issue letters of credit or provide other forms of collateral under certain contractual requirements. Environmental concerns and other factors have led to lower oil and gas representation in certain key equity market indices and may increase our costs to access the equity capital markets. Any inability to access capital markets could adversely impact our financial adaptability and our ability to execute our strategy.
We may engage in risk management transactions designed to mitigate commodity price volatility and other risks that may impede our ability to benefit from commodity price increases and can expose us to similar potential counterparty credit risk as amounts due from the sale of hydrocarbons. We may enter into commodity price hedging arrangements to protect us from commodity price declines. These arrangements may, depending on the instruments used and the level of additional hedges involved, limit any potential upside from commodity price increases. As with accounts receivable from the sale of hydrocarbons, we may be exposed to potential economic loss should a counterparty be unable or unwilling to perform their obligations under the terms of a hedging agreement. In addition, we are exposed to risks related to changes in interest rates and foreign currency values, and may engage in hedging activities to mitigate related volatility.
Regulatory, Legal and Environmental Risks
Our oil and gas operations are subject to environmental risks and environmental, health and safety laws and regulations that can result in significant costs and liabilities. Our oil and gas operations are subject to environmental risks such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage. Our operations are also subject to numerous U.S. federal, state, local and foreign environmental, health and safety laws and regulations. Non-compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial clean-ups, natural resource damages and other liabilities. In addition, increasingly stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating expenses for us. Similarly, we have material legal obligations to dismantle, remove and abandon production facilities and wells that will occur many years in the future, in most cases. These estimates may be impacted by future changes in regulations, solvency of subsequent owners and partners and other uncertainties.
Concerns have been raised in certain jurisdictions where we have operations concerning the safety and environmental impact of the drilling and development of shale oil and gas resources, particularly hydraulic fracturing, water usage, flaring of associated natural gas and air emissions. While we believe that these operations can be conducted safely and with minimal impact on the environment, regulatory bodies are responding to these concerns and may impose moratoriums and new regulations on such drilling operations that would likely have the effect of prohibiting or delaying such operations and increasing their cost.
Climate change, sustainability and other ESG initiatives may result in significant operational changes and expenditures, reduced demand for our products and adversely affect our business. We recognize that climate change and sustainability is a growing global environmental concern. Continuing political and social attention to the issue of climate change and sustainability has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit GHG emissions. These agreements and measures may require, or could result in future legislation and regulatory measures that require, significant equipment modifications, operational changes, taxes, or purchase of emission credits to reduce emission of GHGs from our operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs. For example, the Inflation Reduction Act of 2022 (IRA) includes a methane emissions reduction program for petroleum and natural gas systems, which requires the EPA to impose a “waste emissions charge” on excess methane emissions from certain natural gas and oil sources that are required to report under EPA’s Greenhouse Gas Reporting Program beginning January 1, 2024 and also provides significant funding and incentives for research and development of competing low carbon energy production methods. California recently enacted three climate-related disclosure laws, the Climate Corporate Data Accountability Act, Climate Related Financial Risk Act and Voluntary Carbon Market Disclosures Act, which together will require certain entities doing business in California or taking certain actions in California to report and attain third-party assurance of greenhouse gas emissions information, reporting on climate-related financial risks and reporting regarding the use of voluntary carbon credits and/or carbon reduction claims. Legislation similar to California’s Climate Corporate Data Accountability Act is under consideration in other states. In addition to increased costs for compliance, such legislation, regulations and initiatives could also impact demand as our production is sold to third parties that produce petroleum fuels, which through normal end user consumption result in the emission of GHGs.
We are prioritizing sustainable energy practices to further reduce our carbon footprint while at the same time remaining a successful operating public company. However, various key stakeholders, including our stockholders, employees, suppliers, customers, local communities and others, may have differing approaches to climate change initiatives. If we do not successfully manage expectations across these varied stakeholder interests, it could erode our stakeholders’ trust and thereby affect our reputation. Shareholder activism has been recently increasing in our industry, and stockholders may attempt to effect changes to our business or governance, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. In addition, certain financial institutions, institutional investors and other sources of capital have begun to limit or eliminate their investment in oil and gas activities due to concerns about climate change, which could make it more difficult to finance our business. We continue to focus on developing our ESG practices, and as voluntary and regulatory ESG disclosure standards and policies continue to evolve, we have expanded and expect to further expand our public disclosures in these areas. Such disclosures may reflect aspirational goals, targets, cost estimates and other expectations and assumptions, including over long timelines, which aspirational goals, targets, cost estimates, and other expectations and assumptions are necessarily uncertain and may not be realized. Failure to realize or timely achieve progress on such aspirational goals, targets, cost estimates, and other expectations or assumptions may adversely impact us.
Furthermore, as a result of heightened public awareness and attention to climate change and sustainability as well as continued regulatory initiatives to reduce the use of petroleum fuels, demand for crude oil and other hydrocarbons may be reduced, which may
have an adverse effect on our sales volumes, revenues and margins. The imposition and enforcement of stringent GHG emissions reduction requirements could severely and adversely impact the oil and gas industry and therefore significantly reduce the value of our business. Increasing attention to climate change risks and sustainability has resulted in governmental investigations, and public and private litigation, which could increase our costs or otherwise adversely affect our business. For example, beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. Such actions could adversely impact our business by distracting management and other personnel from their primary responsibilities, require us to incur increased costs, and/or result in reputational harm.
We are subject to changing laws and regulations and other governmental actions that can significantly and adversely affect our business. Political or regulatory developments and governmental actions, including federal, state, local, territorial and foreign laws and regulations may adversely affect our operations and those of our counterparties with whom we have contracted, which may affect our financial results. These actions could result in tax increases retroactively through tax claims or prospectively through changes to applicable statutory tax rates, modification of the tax base, or imposition of new tax types. For example, on August 16, 2022 the U.S. enacted the IRA, which includes a 15% book-income alternative minimum tax on corporations with average adjusted financial statement income over $1 billion for any 3-year period ending with 2022 or later and a 1% excise tax on the fair market value of stock that is repurchased by publicly traded U.S. corporations. The alternative minimum tax and the excise tax are effective in taxable years beginning after December 31, 2022. From time to time since enactment, the Department of Treasury and the Internal Revenue Service have issued interim guidance related to the alternative minimum tax and intend to issue proposed regulations addressing the alternative minimum tax in the future. We continue to evaluate the effect of the new law and any additional guidance on our future cash flows and financial results, including if we become a taxpayer subject to the alternative minimum tax, which would apply to any taxable years beginning on or after January 1, 2024. The impact of the excise tax provision will be dependent on the extent of share repurchases made in future periods. We continue to evaluate the corporate alternative minimum tax and its potential impact on our future U.S. tax expense, cash taxes, and effective tax rate, as well as any other impacts the IRA may have on our financial position and results of operations.
Additionally, governmental actions could include limitations on post-production deductions from royalty payments; limitations or prohibitions on the sales of new oil and gas leases or extensions on existing oil and gas leases; adverse court decisions with respect to the sale of new and existing oil and gas leases or claims related to working interest payments; expropriation or nationalization of property; mandatory government participation, cancellation or amendment of contract rights; imposition of capital controls or blocking of funds; changes in import and export regulations; the imposition of tariffs; and anti-bribery or anti-corruption laws. In recent years, proposals for limitations on access to oil and gas exploration and development opportunities and related litigation have grown in certain areas and may include efforts to reduce access to public and private lands; restriction of exploration and production activities within government-owned and other lands; delaying or canceling permits for drilling or pipeline construction; restrictions or changes to existing pipeline easements; limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated disposal; imposition of set-backs on oil and gas sites; reduction of sulfur content in bunker fuel; delaying or denying air-quality or siting permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm. Costs associated with responding to these anti-development efforts or complying with any new legal or regulatory requirements could significantly and adversely affect our business, financial condition and results of operations.
Political instability globally and in areas where we operate can adversely affect our business. Political instability and civil unrest have affected and may continue to affect the oil and gas markets generally. Some international areas are politically less stable than other areas and may be subject to civil unrest, conflict, insurgency, corruption, security risks and labor unrest. Political instability in areas where we operate may expose our operations to increased risks, including increased difficulty in obtaining required permits and government approvals, enforcing our agreements in those jurisdictions and potential adverse actions by local government authorities. The invasion of Ukraine by Russia in February 2022 has led to disruption, instability, and volatility in global markets and industries, including the oil and gas markets. The U.S. government and other foreign governments imposed severe economic sanctions and export controls against Russia, certain regions of Ukraine and particular entities and individuals, and may impose additional sanctions and controls. The recent war between Israel and Hamas, which began in October 2023, has the potential for further disruption of economic markets, particularly if the conflict expands to other parts of the Middle East. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us or our industry. Furthermore, the threat of terrorism around the world also poses additional risks to our operations and the operations of the oil and gas industry in general. In addition, geographic territorial border disputes may affect our business in certain areas, such as the border dispute between Guyana and Venezuela over a portion of the Stabroek Block.
One of our subsidiaries is the general partner of a publicly traded limited partnership, Hess Midstream LP. The responsibilities associated with being a general partner expose us to a broader range of legal liabilities. Our control of Hess Midstream LP bestows upon us additional duties and obligations including, but not limited to, the obligations associated with managing potential conflicts of interests and additional reporting requirements from the Securities and Exchange Commission. These
heightened duties expose us to additional potential for legal claims that may have a material negative economic impact on our stockholders. Moreover, these increased duties may lead to an increase in compliance costs.
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Cybersecurity Risk Management and Strategy
Cybersecurity is an integral part of our enterprise risk management. We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity and availability of our Digital Systems. Our cybersecurity risk management program includes a cybersecurity incident response plan as well as property and casualty insurance that may cover damages caused as a result of a cybersecurity event.
We design and assess our program based on the NIST CSF. This does not imply that we meet any particular technical standards, specifications, or requirements, only that we use the NIST CSF as a guide to help us identify, assess and manage cybersecurity risks relevant to our business.
Our cybersecurity risk management program is integrated into our overall enterprise risk management program overseen by our Chief Risk Officer, and shares certain methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other areas affecting our business risks, including financial, compliance, EHS, compensation and governance matters, among other topics.
Our cybersecurity risk management program includes:
•risk assessments designed to help identify material cybersecurity risks to critical systems integral to our exploration, development and production activities as well as the activities of our business partners and our broader enterprise information technology environment;
•a security team principally responsible for managing our cybersecurity risk assessment processes, our security controls and our response to cybersecurity incidents;
•the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security controls;
•ongoing cybersecurity awareness and compliance training that occurs quarterly and is mandatory for all our employees, incident response personnel and senior management;
•a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and
•a third-party risk management process for service providers, suppliers and vendors.
We have not identified risks from known cybersecurity threats during the year ended December 31, 2023, including as a result of any prior cybersecurity incidents, that have materially affected us or are reasonably likely to materially affect us, including our operations, business strategy, results of operations, or financial condition.
Additional information about cybersecurity risks we face is discussed in Item 1A. Risk Factors, under the heading “Disruption, failure or cybersecurity attacks affecting or targeting information technology and infrastructure used by the Corporation or our business partners may materially impact our business and operations” which should be read in conjunction with the information above.
Governance
Our Board of Directors (Board) appreciates the rapidly evolving nature of threats presented by cybersecurity incidents and is committed to the prevention, timely detection and mitigation of the effects of any such incidents on the Corporation. The Board considers cybersecurity risk as part of its risk oversight function and has delegated to the Audit Committee (Committee) primary responsibility for oversight of our risk management practices, including oversight of cybersecurity and other information technology risks.
The Committee oversees management’s implementation of our cybersecurity risk management program. The Committee receives presentations on cybersecurity topics from management at least twice a year, including the nature of threats, defense and detection capabilities; incident response plans; and employee training activities. In addition, management updates the Committee, as necessary, regarding any material cybersecurity incidents as well as other incidents with lesser impact potential. The Committee reports to the full Board regarding its activities, including those related to cybersecurity.
Our management team – including our Chief Risk Officer, our Head of Information Technology and our Chief Information Security Officer (CISO) – is responsible for assessing and managing our material risks from cybersecurity threats. The team is primarily responsible for our overall cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our Chief Risk Officer has nearly 20 years of experience in this role at the Corporation and previously served as a consultant with Ernst & Young LLP’s Risk Management and Regulatory Practice, where he assisted financial services and energy trading clients in establishing their risk management infrastructure. Our Head of Information Technology and our CISO each have over 20 years of experience in information technology leadership in oil and gas. Furthermore, our CISO holds a Bachelor of Science in Cyber and Data Security from the University of Arizona and is a Certified Information Systems Security Professional.
Our management team is informed about and monitors the efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel; threat intelligence and other information obtained from governmental, public or private sources, including external consultants engaged by us; and alerts and reports produced by security tools deployed in the information technology environment.
Item 3. Legal Proceedings
Information regarding legal proceedings is contained in Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements and is incorporated herein by reference. Pursuant to Item 103(c)(3)(iii) of Regulation S-K under the Exchange Act, we are required to disclose certain information about environmental proceedings to which a governmental authority is a party if we reasonably believe such proceedings may result in monetary sanctions, exclusive of interest and costs, above a stated threshold. We have elected to apply a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required.
Item 4. Mine Safety Disclosures
None.
PART II
Item 5. Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities
Stock Market Information, Holders and Dividends
Our common stock is listed on the New York Stock Exchange (ticker symbol: HES). At January 31, 2024, there were 2,494 stockholders (based on the number of holders of record) who owned a total of 307,152,064 shares of common stock. In 2023, cash dividends on common stock totaled $1.75 per share per year ($0.4375 per quarter), $1.50 per share per year ($0.3750 per quarter) in 2022 and $1.00 per share per year ($0.2500 per quarter) in 2021.
Performance Graph
Set forth below is a line graph comparing the five-year shareholder returns on a $100 investment in our common stock assuming reinvestment of dividends, against the cumulative total returns for the following:
•Standard & Poor’s (S&P) 500 Stock Index, which includes us.
•2023 Proxy Peer Group as disclosed in our 2023 Proxy Statement, and including us.
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
| | | | | | | | | | | | | | | | | | | | |
| 2018 | 2019 | 2020 | 2021 | 2022 | 2023 |
 Hess Corporation | $100.00 | $167.72 | $135.54 | $192.62 | $373.83 | $384.72 |
 S&P 500 | $100.00 | $131.47 | $155.65 | $200.29 | $163.98 | $207.04 |
 Proxy Peer Group | $100.00 | $100.02 | $63.94 | $117.20 | $196.77 | $193.47 |
Share Repurchase Activities
On March 1, 2023, our Board of Directors approved a new authorization for the repurchase of our common stock in an aggregate amount of up to $1 billion. This new authorization replaced our previous repurchase authorization which was fully utilized at the end of 2022. There were no shares of our common stock repurchased for the year ended December 31, 2023. The Merger Agreement provides that, during the periods from the date of the Merger Agreement until the closing of the Merger, we are subject to certain restrictions that, among other things, restrict our ability to repurchase, redeem or retire any capital stock of the Corporation.
Equity Compensation Plans
Following is information related to our equity compensation plans at December 31, 2023.
| | | | | | | | | | | | | | | | | | | | | | | |
| Plan Category | Number of Securities
to be Issued Upon Exercise of Outstanding Options, Warrants and Rights* | | Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights | | Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in
Column*) |
| Equity compensation plans approved by security holders | 1,509,912 | | (a) | | $ | 78.85 | | | 19,941,906 | | (b) |
| Equity compensation plans not approved by security holders | — | | | | — | | | — | | |
(a)This amount includes 1,509,912 shares of common stock issuable upon exercise of outstanding stock options. This amount excludes 1,020,653 shares of common stock issued as restricted stock pursuant to our equity compensation plans. This amount also excludes 511,781 PSUs. For the PSUs granted in 2021 and 2022, the number of shares of common stock to be issued will range from 0% to 200% based on our total shareholder return (TSR) relative to the TSR of a predetermined group of peer companies and the S&P 500 index over a three‑year performance period ending December 31 of the year prior to settlement of the grant. For the PSU’s granted in 2023, the number of shares of common stock to be issued is based on a comparison of the Corporation’s total shareholder return compound annual growth rate (TSR CAGR) to the TSR CAGR of the SPDR S&P Oil & Gas Exploration and Production ETF (XOP), with a modifier determined by comparing the Corporation’s TSR CAGR to the TSR CAGR of the S&P 500 index, over a three-year performance period ending December 31, 2025. Payout of these PSUs will range from 0% to 200% of the target awards based on the comparison of the Corporation’s TSR CAGR to the XOP’s TSR CAGR. The modifier can only adjust the payout percentage by plus or minus 10%, up to a maximum of 210% or a minimum of 0%.
(b)These securities may be awarded as stock options, restricted stock, PSUs or other awards permitted under our equity compensation plan.
See Note 13, Share‑based Compensation in the Notes to Consolidated Financial Statements for further discussion of our equity compensation plans.
Item 6. [Reserved]
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8, and the information set forth in Part 1, Item 1A. Risk Factors. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations omits certain discussions of our financial condition and results of operations for the year ended December 31, 2022 compared with the year ended December 31, 2021, which can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2022 Annual Report on Form 10-K, which was filed with the Securities and Exchange Commission on February 24, 2023, and such comparisons are incorporated herein by reference. Index
Overview
Hess Corporation is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname. At the Stabroek Block (Hess 30%), offshore Guyana, we and our partners have discovered a significant resource base and are executing a multi-phased development of the block. We currently have three FPSOs producing, and plan to have six FPSOs with an aggregate expected production capacity of more than 1.2 million gross bopd producing by the end of 2027. The discovered resources to date on the block are expected to underpin the potential for up to ten FPSOs.
Our Midstream operating segment, which includes Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP at December 31, 2023, provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.
On October 22, 2023, we entered into the Merger Agreement with Chevron and the Merger Subsidiary. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Subsidiary will be merged with and into Hess, and Hess will be the surviving corporation in the Merger as a direct, wholly-owned subsidiary of Chevron. Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. The transaction is expected to close mid-2024, subject to shareholder and regulatory approvals and other closing conditions. See Part I, Item 1A. Risk Factors for a discussion of risks related to the Merger.
Climate Change, Energy Transition and Our Strategy
We believe climate risks can and should be addressed while at the same time meeting the growing demand for affordable and secure energy, which is essential to ensure a just and orderly energy transition that aligns with the United Nations Sustainable Development Goals. The IEA’s 2023 World Energy Outlook provides three scenarios of global energy demand in 2040 based on varying levels of global response to climate change. Under all of the IEA scenarios, oil and natural gas are expected to be needed for decades to come and we expect that significant investment will be required to meet the world’s projected growing energy needs, both in renewable energy sources and in oil and gas.
Our strategy is to grow our resource base, have a low cost of supply and sustain cash flow growth. Our strategy aligns with the energy transition needed to reach the energy-related Sustainable Development Goals of the United Nations. Our commitment to sustainability starts with our Board of Directors and senior management and is reinforced throughout our organization. Our Board of Directors, led by its Environmental, Health and Safety Committee, is actively engaged in overseeing Hess’ sustainability practices so that sustainability risks and opportunities are taken into account when making strategic decisions. Our Board’s Compensation and Management Development Committee has tied executive compensation to advancing our environmental, health and safety goals.
We have five year GHG reduction targets for 2025, which are to reduce operated Scope 1 and 2 GHG emissions intensity by approximately 50% and methane emissions intensity by approximately 50%, both from 2017 levels. In January 2022, we announced our plan to reduce routine flaring at Hess operated assets to zero by the end of 2025. In December 2022, we announced an agreement
with the Government of Guyana to purchase 37.5 million REDD+ carbon credits, including current and future issuances, for a minimum of $750 million from 2022 through 2032 to prevent deforestation and support sustainable development in Guyana. This agreement adds to the Corporation’s ongoing emissions reduction efforts and is an important part of our commitment to achieve net zero Scope 1 and 2 greenhouse gas emissions on a net equity basis by 2050.
Our business planning includes actions we expect to undertake to continue reducing our carbon footprint consistent with our targets. We also conduct annual scenario planning as a methodology to assess our portfolio’s resilience to differing scenarios of energy supply and demand over the longer term, and to inform our understanding of future risks and opportunities in relation to the potential evolution of energy demand, energy mix, the emergence of new technologies, and possible changes by policymakers with respect to greenhouse gas emissions and climate change.
Consolidated Results
Net income attributable to Hess Corporation was $1,382 million in 2023 compared with $2,096 million in 2022. Excluding items affecting comparability of earnings between periods summarized on page 34, adjusted net income was $1,552 million in 2023 compared with $2,176 million in 2022. Net production averaged 394,000 boepd in 2023 and 344,000 boepd in 2022. The average realized crude oil price, including the effect of hedging, was $75.97 per barrel in 2023 and $85.76 per barrel in 2022. Total proved reserves were 1,370 million boe and 1,256 million boe at December 31, 2023 and December 31, 2022, respectively. Significant 2023 Activities
The following is an update of significant E&P activities during 2023:
E&P assets:
•In North Dakota, net production from the Bakken shale play averaged 182,000 boepd in 2023 (2022: 154,000 boepd). Net production was higher in 2023 reflecting increased drilling and completion activity and higher NGL and natural gas volumes received under percentage of proceeds contracts due to lower commodity prices. NGL and natural gas volumes received under percentage of proceeds contracts were 19,000 boepd in 2023, compared with 10,000 boepd in 2022, due to lower realized NGL and natural gas prices increasing volumes received as consideration for gas processing fees. We added a fourth operated rig in July 2022 and drilled 118 wells and brought 113 wells on production in 2023, bringing the total operated production wells to 1,757 at December 31, 2023. During 2024, we plan to operate four rigs.
•In the Gulf of Mexico, net production averaged 31,000 boepd in 2023 (2022: 31,000 boepd). In July 2023, the Pickerel-1 exploration well (Hess 100%) located in Mississippi Canyon Block 727 completed drilling operations and encountered approximately 90 feet of net pay in high quality, oil bearing, Miocene age reservoir. The well will be a tie-back to the Tubular Bells production facility with first oil expected in mid-2024. In the fourth quarter of 2023, we were the high bidder on 20 leases in the U.S. Department of Interior’s Lease Sale 261 for $88 million and we expect to be awarded these leases in the first quarter of 2024. We also spud the Hess operated Black Pearl development well (Hess 25%) in the fourth quarter of 2023. The well is planned as a tie-back to the Stampede production facility. In 2024, we plan to participate in two wells.
•At the Stabroek Block (Hess 30%), offshore Guyana, net production totaled 115,000 bopd in 2023 (2022: 78,000 bopd). The Liza Unity FPSO, which commenced production in February 2022, reached its initial production capacity of approximately 220,000 gross bopd in July 2022, and increased its production capacity to approximately 250,000 bopd in the third quarter of 2023. Further production optimization work is planned in 2024. The third development, Payara, began producing oil in November 2023 from the Prosperity FPSO and reached its initial production capacity of approximately 220,000 gross bopd in January 2024. In 2023, we sold 37 cargos of crude oil from Guyana compared with 26 cargos in 2022.
Pursuant to the contractual arrangements of the petroleum agreement, a portion of gross production from the block, separate from the joint venture partners’ (Co-Venturers) cost oil and profit oil entitlement, is used to satisfy the Co-Venturers’ income tax liability. This portion of gross production, referred to as tax barrels, is recognized as Co-Venturer production volumes and estimated proved reserves. Net production from Guyana in 2023 included 14,000 bopd of tax barrels (2022: 7,000 bopd; 2021: 0 bopd).
A fourth development, Yellowtail, was sanctioned in April 2022 and will utilize the ONE GUYANA FPSO with an expected initial production capacity of approximately 250,000 gross bopd, with first production expected in 2025. Six drill centers are planned with up to 26 production wells and 25 injection wells.
A fifth development, Uaru, was sanctioned in April 2023 and will utilize the Errea Wittu FPSO with an expected initial production capacity of approximately 250,000 gross bopd, with first production expected in 2026. Ten drill centers are planned with up to 21 production wells and 23 injection wells.
A sixth development, Whiptail, was submitted to the Government of Guyana for approval in the fourth quarter of 2023. Pending government approvals and project sanctioning, the project is expected to have an initial production capacity of approximately 250,000 gross bopd, with first production anticipated in 2027.
A gas to energy project is underway to construct a 130-mile pipeline network and associated infrastructure in order to transport approximately 50 million standard cubic feet of natural gas per day from the Liza Field to a 300 megawatt onshore power plant, which is expected to be constructed and operated by the Government of Guyana. ExxonMobil Guyana Ltd. expects to complete pipeline construction and field hook-up by the end of 2024.
The expiration of the exploration license for the Stabroek Block was extended one year from October 2026 to October 2027, and the end of the first renewal period of the exploration license, which requires the relinquishment of 20% of the acreage not held by discoveries, was extended one year from October 2023 to October 2024, both as a result of force majeure due to the COVID-19 pandemic.
In 2023, the operator drilled a total of three successful exploration and appraisal wells that encountered oil and two unsuccessful exploration wells for which the well costs were expensed. Subsequent to December 31, 2023, the operator completed one successful exploration well and one successful appraisal well. In 2024, the operator plans to utilize six drillships to continue to perform exploration, appraisal, and development activities.
At the Kaieteur Block, offshore Guyana, we relinquished our 20% participating interest, subject to government approval, and recognized exploration expense of $9 million in 2023.
•In the Gulf of Thailand, net production from Block A‑18 of the JDA averaged 36,000 boepd in 2023 (2022: 38,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin averaged 30,000 boepd in 2023 (2022: 26,000 boepd). During 2023, we drilled seven production wells at the JDA and nine production wells at North Malay Basin, and we plan to continue development drilling in 2024.
•In Canada, offshore Newfoundland (Hess 25%), the operator completed drilling of the Ephesus exploration well in June 2023. The well did not encounter commercial quantities of hydrocarbons and well costs incurred of $34 million were recorded to exploration expense in 2023.
The following is an update of significant Midstream activities during 2023:
•Hess Midstream completed two underwritten public equity offerings of an aggregate of approximately 24.3 million Class A shares held by affiliates of Hess and GIP. As a result of these transactions, Hess received net proceeds of $167 million.
•HESM Opco, a consolidated subsidiary of Hess Midstream LP, repurchased an aggregate of approximately 13.6 million HESM Opco Class B units held by affiliates of Hess and GIP in multiple transactions for total proceeds of $400 million, financed by HESM Opco’s revolving credit facility, of which Hess received proceeds of $188 million.
Liquidity and Capital and Exploratory Expenditures
At December 31, 2023, cash and cash equivalents were $1,688 million (2022: $2,486 million) and consolidated debt was $8,613 million (2022: $8,281 million), which includes Hess Midstream debt that is nonrecourse to Hess Corporation of $3,211 million at December 31, 2023 (2022: $2,886 million).
Capital and exploratory expenditures were as follows (in millions):
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| E&P Capital and Exploratory Expenditures: | | | | | |
| United States | | | | | |
| North Dakota | $ | 1,138 | | | $ | 807 | | | $ | 522 | |
| Offshore and other | 290 | | | 224 | | | 103 | |
| Total United States | 1,428 | | | 1,031 | | | 625 | |
| Guyana | 2,518 | | | 1,345 | | | 1,016 | |
| Malaysia and JDA | 189 | | | 275 | | | 154 | |
| Other (a) | 41 | | | 70 | | | 34 | |
| E&P Capital and Exploratory Expenditures | $ | 4,176 | | | $ | 2,721 | | | $ | 1,829 | |
| | | | | | | | | | | | | | | | | |
| Exploration Expenses Charged to Income Included Above: | | | | | |
| United States | $ | 106 | | | $ | 107 | | | $ | 90 | |
| International | 37 | | | 25 | | | 41 | |
| Total Exploration Expenses Charged to Income included above | $ | 143 | | | $ | 132 | | | $ | 131 | |
| | | | | | | | | | | | | | | | | |
| Midstream Capital Expenditures: | | | | | |
| Midstream Capital Expenditures | $ | 246 | | | $ | 232 | | | $ | 183 | |
(a)Other includes our interests in Libya (sold in November 2022) and Denmark (sold in August 2021), and certain non-producing countries.
Our E&P capital and exploratory expenditures are projected to be approximately $4.2 billion in 2024, compared with $4.2 billion in 2023. Capital investment for our Midstream operations is expected to be in the range of $250 million to $275 million in 2024, compared with $246 million in 2023.
Consolidated Results of Operations
Results by Segment:
The after-tax income (loss) by major operating activity is summarized below:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions, except per share amounts) |
| Net Income Attributable to Hess Corporation: | | | | | |
| Exploration and Production | $ | 1,601 | | | $ | 2,396 | | | $ | 770 | |
| Midstream | 252 | | | 269 | | | 286 | |
| Corporate, Interest and Other | (471) | | | (569) | | | (497) | |
| Total | $ | 1,382 | | | $ | 2,096 | | | $ | 559 | |
| Net Income Attributable to Hess Corporation Per Common Share: | | | | | |
| Basic | $ | 4.52 | | | $ | 6.80 | | | $ | 1.82 | |
| Diluted | $ | 4.49 | | | $ | 6.77 | | | $ | 1.81 | |
In the following discussion and elsewhere in this report, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings. Management believes that after-tax amounts are a preferable method of explaining variances in earnings, since they show the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the income tax rate in each tax jurisdiction to pre-tax amounts.
Items Affecting Comparability of Earnings Between Periods:
The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income and affect comparability of earnings between periods. The items in the table below are explained on pages 39 through 41. | | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Items Affecting Comparability of Earnings Between Periods, After Income Taxes: | | | | | |
| Exploration and Production | $ | (101) | | | $ | 22 | | | $ | (118) | |
| Midstream | — | | | — | | | — | |
| Corporate, Interest and Other | (69) | | | (102) | | | — | |
| Total | $ | (170) | | | $ | (80) | | | $ | (118) | |
The following table presents the pre-tax amount of items affecting comparability of income (expense) by financial statement line item in the Statement of Consolidated Income on page 57. The items in the table below are explained on pages 39 through 41. | | | | | | | | | | | | | | | | | |
| | Before Income Taxes |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Gains on asset sales, net | $ | — | | | $ | 98 | | | $ | 29 | |
| Other, net | (17) | | | — | | | — | |
|
|
| Exploration expenses, including dry holes and lease impairment | (52) | | | — | | | — | |
| General and administrative expenses | (52) | | | (124) | | | — | |
| Impairment and other | (82) | | | (54) | | | (147) | |
| Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax | $ | (203) | | | $ | (80) | | | $ | (118) | |
Reconciliations of GAAP and Non-GAAP Measures:
The following table reconciles reported net income attributable to Hess Corporation and adjusted net income attributable to Hess Corporation:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Adjusted Net Income Attributable to Hess Corporation: | | | | | |
| Net income attributable to Hess Corporation | $ | 1,382 | | | $ | 2,096 | | | $ | 559 | |
| Less: Total items affecting comparability of earnings between periods, after-tax | (170) | | | (80) | | | (118) | |
| Adjusted Net Income Attributable to Hess Corporation | $ | 1,552 | | | $ | 2,176 | | | $ | 677 | |
The following table reconciles reported net cash provided by (used in) operating activities and net cash provided by (used in) operating activities before changes in operating assets and liabilities:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Net cash provided by (used in) operating activities before changes in operating assets and liabilities: | | | | | |
| Net cash provided by (used in) operating activities | $ | 3,942 | | | $ | 3,944 | | | $ | 2,890 | |
| Changes in operating assets and liabilities | 552 | | | 1,177 | | | 101 | |
| Net cash provided by (used in) operating activities before changes in operating assets and liabilities | $ | 4,494 | | | $ | 5,121 | | | $ | 2,991 | |
Adjusted net income attributable to Hess Corporation is a non-GAAP financial measure, which we define as reported net income attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods, which are summarized on pages 39 through 41. Management uses adjusted net income to evaluate the Corporation’s operating performance and believes that investors’ understanding of our performance is enhanced by disclosing this measure, which excludes certain items that management believes are not directly related to ongoing operations and are not indicative of future business trends and operations. Net cash provided by (used in) operating activities before changes in operating assets and liabilities presented in this report is a non-GAAP measure, which we define as reported net cash provided by (used in) operating activities excluding changes in operating assets and liabilities. Management uses net cash provided by (used in) operating activities before changes in operating assets and liabilities to evaluate the Corporation’s ability to internally fund capital expenditures, pay dividends and service debt and believes that
investors’ understanding of our ability to generate cash to fund these items is enhanced by disclosing this measure, which excludes working capital and other movements that may distort assessment of our performance between periods.
These measures are not, and should not be viewed as, substitutes for GAAP net income and net cash provided by (used in) operating activities.
Comparison of Results
Exploration and Production
Following is a summarized statement of income for our E&P operations:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Revenues and Non-Operating Income | | | | | |
| Sales and other operating revenues | $ | 10,500 | | | $ | 11,324 | | | $ | 7,473 | |
| Gains on asset sales, net | — | | | 76 | | | 29 | |
| Other, net | 50 | | | 102 | | | 64 | |
| Total revenues and non-operating income | 10,550 | | | 11,502 | | | 7,566 | |
| Costs and Expenses | | | | | |
| Marketing, including purchased oil and gas | 2,809 | | | 3,394 | | | 2,119 | |
| Operating costs and expenses | 1,479 | | | 1,186 | | | 965 | |
| Production and severance taxes | 216 | | | 255 | | | 172 | |
| Midstream tariffs | 1,245 | | | 1,193 | | | 1,094 | |
| Exploration expenses, including dry holes and lease impairment | 317 | | | 208 | | | 162 | |
| General and administrative expenses | 254 | | | 224 | | | 191 | |
| Depreciation, depletion and amortization | 1,852 | | | 1,520 | | | 1,361 | |
| Impairment and other | 82 | | | 54 | | | 147 | |
| Total costs and expenses | 8,254 | | | 8,034 | | | 6,211 | |
| Results of Operations Before Income Taxes | 2,296 | | | 3,468 | | | 1,355 | |
| Provision for income taxes | 695 | | | 1,072 | | | 585 | |
| Net Income Attributable to Hess Corporation | $ | 1,601 | | | $ | 2,396 | | | $ | 770 | |
Excluding the E&P items affecting comparability of earnings between periods in the table on page 39, the changes in E&P results are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs, Midstream tariffs, DD&A expense, exploration expenses and income taxes, as discussed below.
Selling Prices: Average worldwide realized crude oil selling prices, including hedging, were 11% lower in 2023 compared with the prior year, primarily due to the decrease in Brent and WTI crude oil prices. In addition, realized worldwide selling prices for NGL decreased in 2023 by 41% and worldwide natural gas prices decreased in 2023 by 23%, compared with the prior year. In total, lower realized selling prices reduced after-tax results by approximately $1,560 million, compared with 2022. Our average selling prices were as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| Average Selling Prices (a) | | | | | |
| Crude Oil – Per Barrel (Including Hedging) | | | | | |
| United States | | | | | |
| North Dakota | $ | 70.44 | | | $ | 81.06 | | | $ | 55.57 | |
| Offshore | 72.06 | | | 81.38 | | | 60.09 | |
| Total United States | 70.80 | | | 81.14 | | | 56.64 | |
| Guyana | 80.72 | | | 89.86 | | | 68.57 | |
| Malaysia and JDA | 75.51 | | | 89.77 | | | 71.00 | |
| Other (b) | — | | | 93.67 | | | 66.39 | |
| Worldwide | 75.97 | | | 85.76 | | | 60.08 | |
| | | | | |
| Crude Oil – Per Barrel (Excluding Hedging) | | | | | |
| United States | | | | | |
| North Dakota | $ | 73.80 | | | $ | 91.26 | | | $ | 59.90 | |
| Offshore | 75.39 | | | 91.51 | | | 64.77 | |
| Total United States | 74.15 | | | 91.32 | | | 61.05 | |
| Guyana | 82.20 | | | 96.52 | | | 71.07 | |
| Malaysia and JDA | 75.51 | | | 89.77 | | | 71.00 | |
| Other (b) | — | | | 101.92 | | | 69.25 | |
| Worldwide | 78.29 | | | 94.15 | | | 63.90 | |
| | | | | |
| Natural Gas Liquids – Per Barrel | | | | | |
| United States | | | | | |
| North Dakota | $ | 20.77 | | | $ | 35.09 | | | $ | 30.74 | |
| Offshore | 20.87 | | | 35.24 | | | 26.40 | |
| Worldwide | 20.77 | | | 35.09 | | | 30.40 | |
| | | | | |
| Natural Gas – Per Mcf | | | | | |
| United States | | | | | |
| North Dakota | $ | 1.68 | | | $ | 5.50 | | | $ | 4.08 | |
| Offshore | 2.16 | | | 6.21 | | | 3.25 | |
| Total United States | 1.76 | | | 5.66 | | | 3.82 | |
| Malaysia and JDA | 5.95 | | | 5.62 | | | 5.15 | |
| Other (b) | — | | | 5.93 | | | 3.40 | |
| Worldwide | 4.32 | | | 5.64 | | | 4.60 | |
(a)Selling prices in the United States and Guyana are adjusted for certain processing and distribution fees included in Marketing expenses. Excluding these fees worldwide selling prices for 2023 would be $79.30 per barrel for crude oil (including hedging) (2022: $89.50; 2021: $64.25), $81.62 per barrel for crude oil (excluding hedging) (2022: $97.89; 2021: $68.07), $21.01 per barrel for NGL (2022: $35.44; 2021: $30.61) and $4.47 per mcf for natural gas (2022: $5.76; 2021: $4.71).
(b)Other includes our interests in Libya (sold in November 2022) and Denmark (sold in August 2021).
Crude oil hedging activities in 2023 were a net loss of $190 million before and after income taxes, and a net loss of $585 million before and after income taxes in 2022.
Production Volumes: Our daily worldwide net production was as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In thousands) |
| Crude Oil – Barrels | | | | | |
| United States | | | | | |
| North Dakota | 83 | | | 75 | | | 80 | |
| Offshore | 22 | | | 22 | | | 29 | |
| Total United States | 105 | | | 97 | | | 109 | |
| Guyana | 115 | | | 78 | | | 30 | |
| Malaysia and JDA | 5 | | | 4 | | | 3 | |
| Other (a) | — | | | 15 | | | 21 | |
| Total | 225 | | | 194 | | | 163 | |
| | | | | |
| Natural Gas Liquids – Barrels | | | | | |
| United States | | | | | |
| North Dakota | 67 | | | 53 | | | 49 | |
| Offshore | 2 | | | 2 | | | 4 | |
| Total United States | 69 | | | 55 | | | 53 | |
| | | | | |
| Natural Gas – Mcf | | | | | |
| United States | | | | | |
| North Dakota | 191 | | | 156 | | | 162 | |
| Offshore | 43 | | | 44 | | | 72 | |
| Total United States | 234 | | | 200 | | | 234 | |
| Malaysia and JDA | 368 | | | 360 | | | 347 | |
| Other (a) | — | | | 10 | | | 10 | |
| Total | 602 | | | 570 | | | 591 | |
| | | | | |
| Barrels of Oil Equivalent | 394 | | | 344 | | | 315 | |
| | | | | |
| Crude oil and natural gas liquids as a share of total production | 75 | % | | 72 | % | | 69 | % |
(a)Other includes our interests in Libya (sold in November 2022) and Denmark (sold in August 2021). Net production from Libya was 17,000 boepd boepd for 2022 (2021: 20,000 boepd). Net production from Denmark was 3,000 boepd for 2021.
Net production variances related to 2023 and 2022 are summarized as follows:
United States: North Dakota net production was higher in 2023, reflecting increased drilling and completion activity and higher NGL and natural gas volumes received under percentage of proceeds contracts due to lower commodity prices.
International: Net production in Guyana was higher in 2023, primarily due to the Liza Unity FPSO, which commenced production in February 2022 and reached its initial production capacity of approximately 220,000 gross bopd in July 2022. The Liza Unity FPSO increased its production capacity to approximately 250,000 gross bopd in the third quarter of 2023. The third development, Payara, began producing oil in November 2023 from the Prosperity FPSO and reached its initial production capacity of approximately 220,000 gross bopd in January 2024. Net production from Guyana included 14,000 bopd of tax barrels in 2023 (2022: 7,000 bopd).
Sales Volumes: Higher sales volumes in 2023 increased after-tax earnings by approximately $1,650 million. Net worldwide sales volumes from Hess net production, which excludes sales volumes of crude oil, NGLs and natural gas purchased from third parties, were as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In thousands) |
Crude oil – barrels (a) | 81,941 | | | 69,679 | | | 63,540 | |
Natural gas liquids – barrels | 25,184 | | | 19,843 | | | 19,406 | |
Natural gas – mcf | 219,750 | | | 208,001 | | | 215,589 | |
| Barrels of Oil Equivalent | 143,750 | | | 124,189 | | | 118,878 | |
| | | | | |
Crude oil – barrels per day | 225 | | | 191 | | | 174 | |
Natural gas liquids – barrels per day | 69 | | | 54 | | | 53 | |
Natural gas – mcf per day | 602 | | | 570 | | | 591 | |
| Barrels of Oil Equivalent Per Day | 394 | | | 340 | | | 326 | |
(a)Sales volumes in 2021 include 4.2 million barrels of crude oil that were stored on VLCCs at December 31, 2020 and sold in the first quarter of 2021.
Marketing, including purchased oil and gas (Marketing expense): Marketing expense is mainly comprised of costs to purchase crude oil, NGL and natural gas from our partners in Hess operated wells or other third parties, primarily in the U.S., and transportation and other distribution costs for U.S. and Guyana marketing activities. Marketing expense was lower in 2023, compared to 2022, primarily due to lower prices paid for purchased volumes.
Cash Operating Costs: Cash operating costs consist of operating costs and expenses, production and severance taxes and E&P general and administrative expenses. Cash operating costs increased in 2023, compared to 2022, primarily due to the production ramp up in Guyana following the startup of Liza Phase 2 in February 2022 and Payara in November 2023, increased maintenance activity in North Dakota, and higher workover costs in the Gulf of Mexico.
Midstream Tariffs Expense: Tariffs expense increased in 2023, compared to 2022, primarily due to higher throughput volumes and tariff rates, partially offset by lower fees incurred under minimum volume commitments.
DD&A Expense: DD&A expense was higher in 2023, compared to 2022, primarily due to higher production from Guyana following the startup of Liza Phase 2 in February 2022 and first production from Payara in November 2023, and Malaysia and JDA due to new wells and facilities online in 2023.
Unit Costs: Unit cost per boe information is based on total E&P net production volumes and excludes items affecting comparability of earnings as disclosed on page 39. Actual unit costs are as follows: | | | | | | | | | | | | | | | | | |
| | Actual |
| | 2023 | | 2022 | | 2021 |
| Cash operating costs (a) | $ | 13.57 | | | $ | 13.28 | | | $ | 11.55 | |
| DD&A expense (b) | 12.89 | | | 12.13 | | | 11.84 | |
| Total Production Unit Costs | $ | 26.46 | | | $ | 25.41 | | | $ | 23.39 | |
(a)Cash operating costs per boe, excluding Libya, were $13.77 in 2022 (2021: $12.11).
(b)DD&A expense per boe, excluding Libya, was $12.59 in 2022 (2021: $12.43).
Exploration Expenses: Exploration expenses, including items affecting comparability of earnings described below, were as follows:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Exploratory dry hole costs (a) | $ | 147 | | | $ | 56 | | | $ | 11 | |
| Exploration lease impairment | 27 | | | 20 | | | 20 | |
| Geological and geophysical expense and exploration overhead | 143 | | | 132 | | | 131 | |
| | $ | 317 | | | $ | 208 | | | $ | 162 | |
(a)In 2023, dry hole costs primarily related to the Ephesus exploration well, offshore Newfoundland, Canada, the Kokwari-1 and Fish/Tarpon-1 exploration wells at the Stabroek Block, offshore Guyana, and the write-off of a previously capitalized exploratory well (see Items Affecting Comparability of Earnings Between Periods on page 39). Dry hole costs primarily related to the Fish/Tarpon-1 well and Banjo-1 well in 2022 and the Koebi-1 well in 2021 at the Stabroek Block, offshore Guyana.
Income Taxes: In 2023, E&P income tax expense was $695 million compared to $1,072 million in 2022. Income tax expense from Libya operations, sold in November 2022, was $527 million in 2022. The absence of Libya tax expense in 2023 compared to 2022 was partially offset by higher income tax expense in Guyana as a result of higher pre-tax income.
We are generally not recognizing deferred tax benefit or expense in certain countries while we maintain valuation allowances against net deferred tax assets in these jurisdictions in accordance with U.S. GAAP. As of December 31, 2023, we have a valuation allowance in our Consolidated Balance Sheet of $3,652 million. In December 2023, the valuation allowance established against the portion of the net deferred tax assets in Malaysia related to the Marginal Field tax ring-fence was released in the amount of $33 million as a result of the emergence from a cumulative loss position and positive evidence from forecasted pre-tax income from operations. See E&P Items Affecting Comparability of Earnings Between Periods below. The remaining valuation allowance in Malaysia is associated with net deferred tax assets of other tax ring-fences which lack sufficient positive evidence to support realizability. While we emerged from a recent cumulative loss position in the U.S. (non-Midstream) in 2023, the cumulative income position is near breakeven. Until we see a more significant and sustained pattern of objectively verifiable income, we do not assign significant weight to subjective long-term projections of future income and thus maintain a full valuation allowance against our U.S. (non-Midstream) federal and state deferred tax assets. If anticipated future earnings are exceeded, sufficient positive evidence may become available to support the release of valuation allowance in the future. This would result in the recognition of certain deferred tax assets on the balance sheet and a decrease to income tax expense for the period in which the release is recorded.
Actual effective tax rates are as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | % | | % | | % |
| Effective income tax benefit (expense) rate | (30) | | (31) | | (43) |
| Adjusted effective income tax benefit (expense) rate (a) | (30) | | (19) | | (15) |
(a)Excludes any contribution from Libya, sold in November 2022, and items affecting comparability of earnings.
Items Affecting Comparability of Earnings Between Periods: Reported E&P earnings include the following items affecting comparability of income (expense):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Before Income Taxes | | After Income Taxes |
| | 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 |
| | | | | | | | | | | |
| | (In millions) |
| Impairment and other | $ | (82) | | | $ | (54) | | | $ | (147) | | | $ | (82) | | | $ | (54) | | | $ | (147) | |
Dry hole expenses | (52) | | | — | | | — | | | (52) | | | — | | | — | |
| Gains on asset sales, net | — | | | 76 | | | 29 | | | — | | | 76 | | | 29 | |
| Release of deferred tax asset valuation allowance | — | | | — | | | — | | | 33 | | | — | | | — | |
| | $ | (134) | | | $ | 22 | | | $ | (118) | | | $ | (101) | | | $ | 22 | | | $ | (118) | |
The pre-tax amounts of E&P items affecting comparability of income (expense) as presented in the Statement of Consolidated Income are as follows:
| | | | | | | | | | | | | | | | | |
| | Before Income Taxes |
| 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
|
| Gains on asset sales, net | $ | — | | | $ | 76 | | | $ | 29 | |
|
|
|
|
|
| Exploration expenses, including dry holes and lease impairment | (52) | | | — | | | — | |
| Impairment and other | (82) | | | (54) | | | (147) | |
| | $ | (134) | | | $ | 22 | | | $ | (118) | |
2023:
•Dry hole expenses: We recorded a pre-tax charge of $52 million ($52 million after income taxes) to write-off the Huron-1 exploration well in the Gulf of Mexico which completed in 2022, based on the decision by the Corporation and its partners in the fourth quarter of 2023 to exit the project. See Note 3, Property, Plant and Equipment in the Notes to Consolidated Financial Statements.
•Impairment and other: We recorded a pre-tax charge of $82 million ($82 million after income taxes) that resulted from revisions to our estimated abandonment obligations in the West Delta Field in the Gulf of Mexico. These abandonment obligations were assigned to us as a former owner after they were discharged from Fieldwood Energy LLC as part of its approved bankruptcy plan in 2021. See Note 12, Impairment and Other in the Notes to Consolidated Financial Statements.
•Release of deferred tax asset valuation allowance: We recorded a noncash income tax benefit of $33 million, which resulted from the reversal of a valuation allowance against net deferred tax assets in Malaysia.
2022:
•Gains on asset sales, net: We recognized a pre-tax gain of $76 million ($76 million after income taxes) associated with the sale of our interest in the Waha Concession in Libya.
•Impairment and other: We recorded charges of $28 million ($28 million after income taxes) that resulted from updates to our estimated abandonment liabilities for non-producing properties in the Gulf of Mexico and $26 million ($26 million after income taxes) related to the Penn State Field in the Gulf of Mexico. See Note 12, Impairment and Other in the Notes to Consolidated Financial Statements.
2021:
•Gains on asset sales, net: We recognized a pre-tax gain of $29 million ($29 million after income taxes) associated with the sale of our interests in Denmark.
•Impairment and other: We recorded a charge of $147 million ($147 million after income taxes) in connection with estimated abandonment obligations in the West Delta Field in the Gulf of Mexico. These abandonment obligations were assigned to us as a former owner after they were discharged from Fieldwood Energy LLC as part of its approved bankruptcy plan. See Note 12, Impairment and Other in the Notes to Consolidated Financial Statements.
Midstream
Following is a summarized statement of income for our Midstream operations:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Revenues and Non-Operating Income | | | | | |
| Sales and other operating revenues | $ | 1,349 | | | $ | 1,273 | | | $ | 1,204 | |
|
| Other, net | 8 | | | 8 | | | 10 | |
| Total revenues and non-operating income | 1,357 | | | 1,281 | | | 1,214 | |
| Costs and Expenses | | | | | |
| Operating costs and expenses | 313 | | | 280 | | | 289 | |
| General and administrative expenses | 26 | | | 23 | | | 22 | |
| Interest expense | 179 | | | 150 | | | 105 | |
| Depreciation, depletion and amortization | 193 | | | 181 | | | 166 | |
| Total costs and expenses | 711 | | | 634 | | | 582 | |
| Results of Operations Before Income Taxes | 646 | | | 647 | | | 632 | |
| Provision for income taxes | 38 | | | 27 | | | 15 | |
| Net income | 608 | | | 620 | | | 617 | |
| Less: Net income attributable to noncontrolling interests | 356 | | | 351 | | | 331 | |
| Net Income Attributable to Hess Corporation | $ | 252 | | | $ | 269 | | | $ | 286 | |
Sales and other operating revenues increased from 2022 primarily due to higher throughput volumes and tariff rates, partially offset by lower fees earned from minimum volume commitments. Operating costs and expenses increased from 2022 primarily due to higher maintenance costs. Interest expense increased from 2022 primarily due to higher interest rates on the credit facilities and higher borrowings on the revolving credit facility. DD&A expense increased from 2022 primarily due to additional assets placed in service. Provision for income taxes increased from 2022 primarily driven by increased ownership of HESM Opco by Hess Midstream LP following the equity offerings and unit repurchase transactions in 2022 and 2023.
Corporate, Interest and Other
The following table summarizes Corporate, Interest and Other expenses:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Corporate and other expenses (excluding items affecting comparability) | $ | 103 | | | $ | 124 | | | $ | 121 | |
| Interest expense | 347 | | | 353 | | | 376 | |
| Less: Capitalized interest | (48) | | | (10) | | | — | |
| Interest expense, net | 299 | | | 343 | | | 376 | |
| Corporate, Interest and Other expenses before income taxes | 402 | | | 467 | | | 497 | |
| Provision (benefit) for income taxes | — | | | — | | | — | |
| Corporate, Interest and Other expenses after income taxes | 402 | | | 467 | | | 497 | |
| Items affecting comparability of earnings between periods, after income taxes | 69 | | | 102 | | | — | |
| Total Corporate, Interest and Other expenses after income taxes | $ | 471 | | | $ | 569 | | | $ | 497 | |
Corporate and other expenses, excluding items affecting comparability, were lower in 2023 compared to 2022 primarily due to higher interest income partially offset by higher legal and professional fees and other administrative expenses. Interest expense, net was lower in 2023 compared to 2022 due to capitalized interest that commenced upon sanctioning of the Yellowtail development in Guyana in April 2022 and the Uaru development in Guyana in April 2023.
Items Affecting Comparability of Earnings Between Periods: Corporate, Interest and Other results included the following items affecting comparability of income (expense):
2023:
•Litigation costs: We incurred pre-tax charges totaling $52 million ($52 million after income taxes) for litigation related costs associated with our former downstream business, HONX, Inc., which are included in General and administrative expenses in the Statement of Consolidated Income. See Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
•Pension settlement: We recorded a noncash charge to recognize unamortized actuarial losses of $17 million ($17 million after income taxes) resulting from the payment of lump sums to certain participants in the Hess Corporation Employees’ Pension Plan. The charge is included in Other, net in the Statement of Consolidated Income. See Note 9, Retirement Plans in the Notes to Consolidated Financial Statements.
2022:
•Gains on asset sales, net: We recorded a pre-tax gain of $22 million ($22 million after income taxes) associated with the sale of real property related to our former downstream business.
•Litigation costs: We incurred pre-tax charges totaling $124 million ($124 million after income taxes) for litigation related costs associated with our former downstream business, HONX, Inc., which are included in General and administrative expenses in the Statement of Consolidated Income. See Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:
| | | | | | | | | | | |
| | 2023 | | 2022 |
| | | |
| | (In millions, except ratio) |
| Cash and cash equivalents (a) | $ | 1,688 | | | $ | 2,486 | |
| Current portion of long-term debt | 311 | | | 3 | |
| Total debt (b) | 8,613 | | | 8,281 | |
| Total equity | 9,602 | | | 8,496 | |
| Debt to capitalization ratio for debt covenants (c) | 33.6 | % | | 36.1 | % |
(a)Includes $6 million of cash attributable to our Midstream segment at December 31, 2023 (2022: $4 million) of which, $5 million is held by Hess Midstream LP at December 31, 2023 (2022: $3 million).
(b)Includes $3,211 million of debt outstanding from our Midstream segment at December 31, 2023 (2022: $2,886 million) that is non-recourse to Hess Corporation.
(c)Total Consolidated Debt of Hess Corporation (including finance leases and excluding Midstream non-recourse debt) as a percentage of Total Capitalization of Hess Corporation as defined under Hess Corporation’s revolving credit facility financial covenants. Total Capitalization excludes the impact of noncash impairment charges and non-controlling interests. See Note 7, Debt in the Notes to Consolidated Financial Statements.
Cash Flows
The following table sets forth a summary of our cash flows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Net cash provided by (used in): | | | | | |
| Operating activities | $ | 3,942 | | | $ | 3,944 | | | $ | 2,890 | |
| Investing activities | (4,113) | | | (2,555) | | | (1,325) | |
| Financing activities | (627) | | | (1,616) | | | (591) | |
| Net Increase (Decrease) in Cash and Cash Equivalents | $ | (798) | | | $ | (227) | | | $ | 974 | |
Operating Activities: Net cash provided by operating activities was $3,942 million in 2023 (2022: $3,944 million), while net cash provided by operating activities before changes in operating assets and liabilities was $4,494 million in 2023 (2022: $5,121 million). Net cash provided by operating activities before changes in operating assets and liabilities decreased from 2022 primarily due to lower realized selling prices partially offset by higher sales volumes. Changes in operating assets and liabilities in 2023 reduced net cash provided by operating activities by $552 million primarily due to premiums paid for crude oil hedge contracts and payments for abandonment activities. Changes in operating assets and liabilities in 2022 reduced net cash provided by operating activities by $1,177 million reflecting payments of approximately $470 million for accrued Libyan income tax and royalties at December 31, 2021, premiums paid for crude oil hedge contracts, payments for abandonment activities, and the purchase of REDD+ carbon credits.
Investing Activities: Additions to Property, Plant and Equipment were $4,108 million in 2023 (2022: $2,725 million). The increase is primarily due to development activities in Guyana and higher drilling activity in the Bakken. Proceeds from asset sales were $3 million in 2023 (2022: $178 million).
Financing Activities: Common stock dividends paid were $539 million in 2023 (2022: $465 million) reflecting a 17% increase in our declared dividend on common stock. In 2022, we paid $630 million for settled common stock repurchases and we repaid the remaining $500 million outstanding under our $1.0 billion term loan.
Net borrowings (repayments) of debt with maturities of 90 days or less in 2023 related to the HESM Opco revolving credit facility, while borrowings in 2022 resulted from the issuance by HESM Opco of $400 million of 5.500% fixed-rate senior unsecured notes due 2030. The proceeds from these borrowings were used to finance the repurchases of HESM Opco Class B units. In 2023, we received net proceeds of $167 million from the public offering of Class A shares in Hess Midstream LP (2022: $146 million). Net cash outflows to noncontrolling interests were $550 million in 2023 (2022: $510 million) which included $212 million paid to GIP for the repurchase by HESM Opco of GIP-owned Class B units (2022: $200 million).
Future Capital Requirements and Resources
At December 31, 2023, we had $1.68 billion in cash and cash equivalents, excluding Midstream, and total liquidity, including available committed credit facilities, of approximately $5.0 billion. In 2024, based on current forward strip crude oil prices, we expect cash flow from operating activities and cash and cash equivalents at December 31, 2023 will be sufficient to fund any upcoming debt maturities, and our capital investment and capital return programs. Depending on market conditions, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: reduce the planned capital program and other cash outlays, including dividends, pursue asset sales, borrow against our committed revolving credit facility, or issue debt or equity securities. These actions are subject to certain limitations under the Merger Agreement. See Part I, Item 1A. Risk Factors for a discussion of risks related to the Merger.
The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expiration Date | | Capacity | | Borrowings | | Letters of
Credit
Issued | | Total
Used | | Available
Capacity |
| | | | | | | | | | | |
| | | | (In millions) |
| Hess Corporation | | | | | | | | | | | |
| Revolving credit facility | July 2027 | | $ | 3,250 | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,250 | |
| Committed lines | Various (a) | | 100 | | | — | | | 2 | | | 2 | | | 98 | |
| Uncommitted lines | Various (a) | | 86 | | | — | | | 86 | | | 86 | | | — | |
| Total – Hess Corporation | | | $ | 3,436 | | | $ | — | | | $ | 88 | | | $ | 88 | | | $ | 3,348 | |
| Midstream | | | | | | | | | | | |
| Revolving credit facility (b) | July 2027 | | $ | 1,000 | | | $ | 340 | | | $ | — | | | $ | 340 | | | $ | 660 | |
| Total – Midstream | | | $ | 1,000 | | | $ | 340 | | | $ | — | | | $ | 340 | | | $ | 660 | |
(a)Committed and uncommitted lines have expiration dates through 2024.
(b)This credit facility may only be utilized by HESM Opco and is non-recourse to Hess Corporation.
Hess Corporation:
The revolving credit facility can be used for borrowings and letters of credit. Borrowings on the facility will generally bear interest at 1.400% above SOFR, though the interest rate is subject to adjustment based on the credit rating of the Corporation’s senior, unsecured, non-credit enhanced long-term debt. The revolving credit facility is subject to customary representations, warranties, customary events of default and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the revolving credit facility). The indentures for the Corporation’s fixed-rate senior unsecured notes limit the ratio of secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As of December 31, 2023, Hess Corporation was in compliance with these financial covenants. The most restrictive of the financial covenants relating to our fixed-rate senior unsecured notes and our revolving credit facility would allow us to borrow up to an additional $2,515 million of secured debt at December 31, 2023.
We have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.
Midstream:
At December 31, 2023, HESM Opco had $1.4 billion of senior secured syndicated credit facilities, consisting of a $1.0 billion revolving credit facility and a $400 million term loan facility. Borrowings under the term loan facility will generally bear interest at SOFR plus an applicable margin ranging from 1.650% to 2.550%, while the applicable margin for the syndicated revolving credit facility ranges from 1.375% to 2.050%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at December 31, 2023. The credit facilities are secured by first-priority perfected liens on substantially all of the assets of HESM Opco and its direct and indirect wholly owned material domestic subsidiaries, including equity interests directly owned by such entities, subject to certain customary exclusions. At December 31, 2023, borrowings of $340 million were drawn under HESM Opco’s revolving credit facility, and borrowings of $397 million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan facility. Borrowings under these credit facilities are non-recourse to Hess Corporation.
Credit Ratings
All three major credit rating agencies that rate the senior unsecured debt of Hess Corporation have assigned an investment grade credit rating. At December 31, 2023, our credit ratings were BBB- at S&P Global Ratings, Baa3 at Moody’s Investors Service, and BBB at Fitch Ratings. Subsequent to the announcement of the Merger all three agencies placed our credit ratings on review for positive action in connection with the Merger.
At December 31, 2023, HESM Opco’s senior unsecured debt is rated BB+ by S&P Global Ratings and Fitch Ratings, and Ba2 by Moody’s Investors Service.
Cash Requirements:
Our cash obligations and commitments over the next twelve months include accounts payable, accrued liabilities, the current portion of long-term debt, interest, lease payments, and purchase obligations which cover a portion of our planned capital expenditure program in 2024 and include commitments for oil and gas production expenses, carbon credits, transportation and related contracts, seismic purchases and other normal business expenses.
Our long-term cash obligations and commitments include:
•Debt and interest: See Note 7, Debt in the Notes to Consolidated Financial Statements.
•Operating and finance leases: The Corporation and certain of its subsidiaries lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space for varying periods. See Note 6, Leases in the Notes to Consolidated Financial Statements.
•Purchase obligations: We were contractually committed at December 31, 2023 for certain long-term capital expenditures and operating expenses. Long-term obligations for operating expenses include commitments for oil and gas production expenses, transportation and related contracts, carbon credits, seismic purchases and other normal business expenses. See Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
•Asset retirement obligations: See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements.
•Post-retirement plan liabilities: We have certain unfunded post-retirement plans, including our post-retirement medical plan. See Note 9, Retirement Plans in the Notes to Consolidated Financial Statements.
•Uncertain income tax positions: See Note 14, Income Taxes in the Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements
See Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
Foreign Operations
We conduct E&P activities outside the U.S., principally in Guyana, the Joint Development Area of Malaysia/Thailand, Malaysia, and Suriname. Therefore, we are subject to the risks associated with foreign operations. See Part 1, Item 1A. Risk Factors for further details.
Critical Accounting Policies and Estimates
Accounting policies and estimates affect the recognition of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income. The accounting methods used can affect net income, equity and various financial statement ratios. However, our accounting policies generally do not change cash flows or liquidity.
Accounting for Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves, and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.
Crude Oil and Natural Gas Reserves: The determination of estimated proved reserves is a significant element in arriving at the results of operations of E&P activities. The estimates of proved reserves affect well capitalizations, the unit of production depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets.
For reserves to be booked as proved they must be determined with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. In addition, government and project operator approvals must be obtained and, depending on the amount of the project cost, senior management or the Board of
Directors must commit to fund the project. We maintain our own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. Our technical staff update reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management review. We also engage an independent third-party consulting firm to audit approximately 80% of our total proved reserves each year.
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. As discussed in Part 1, Item 1A. Risk Factors, crude oil prices are volatile which can have an impact on our proved reserves. Crude oil prices used in the determination of proved reserves at December 31, 2023 were $78.10 per barrel for WTI (2022: $94.13) and $82.51 per barrel for Brent (2022: $97.98). At December 31, 2023, spot prices closed at $71.65 per barrel for WTI and $77.59 per barrel for Brent. If crude oil prices in 2024 are at levels below that used in determining 2023 proved reserves, we may recognize negative revisions to our December 31, 2024 proved undeveloped reserves. In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost structures. Conversely, price increases in 2024 above those used in determining 2023 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2024. It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2024, due to numerous currently unknown factors, including 2024 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions in proved reserves related to 2024 reservoir performance, the levels to which industry costs will change in response to 2024 crude oil prices, and management’s plans as of December 31, 2024 for developing proved undeveloped reserves. A 10% change in proved developed and proved undeveloped reserves at December 31, 2023 would result in an approximate $225 million pre-tax change in depreciation, depletion, and amortization expense for 2024 based on projected production volumes. See the Supplementary Oil and Gas Data on pages 92 through 101 in the accompanying financial statements for additional information on our oil and gas reserves. Impairment of Long-lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long‑lived assets are tested based on identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve-month average prices.
Our impairment tests of long-lived E&P producing assets are based on our best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed. We could experience an impairment in the future if one or a combination of the following occur: the projected production volumes from oil and gas fields decrease, crude oil and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase significantly.
Hess Midstream LP: We consolidate the activities of our interest in Hess Midstream LP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power through Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. This conclusion was based on a qualitative analysis that considered Hess Midstream LP’s governance structure, the commercial agreements between Hess Midstream LP and us, and the voting rights established between the members.
Income Taxes: Judgments are required in the determination and recognition of income tax assets and liabilities in the financial statements. These judgments include the requirement to recognize the financial statement effect of a tax position only when management believes it is more likely than not, based on the technical merits, that the position will be sustained upon examination.
We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recognized deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If,
when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is established to reduce the deferred tax assets to the amount that is expected to be realized.
The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves, selling prices, and other subjective operating assumptions that are consistent with internal business forecasts. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax benefits. A recent cumulative loss constitutes objective negative evidence to which the accounting standards require we assign significant weight relative to subjective evidence such as our estimates of future taxable income. We are generally not recognizing deferred tax benefit or expense in certain countries, primarily the United States (non-Midstream) while we maintain valuation allowances against net deferred tax assets in these jurisdictions.
At December 31, 2023, the Consolidated Balance Sheet reflects a $3,652 million valuation allowance against the net deferred tax assets for multiple jurisdictions based on the evaluation of the accounting standards described above. The amount of the deferred tax asset considered realizable, however, could be adjusted if objective negative evidence in the form of cumulative losses is no longer present and additional weight can be given to subjective evidence. In December 2023, the valuation allowance established against the portion of the net deferred tax assets in Malaysia related to the Marginal Field tax ring-fence was released in the amount of $33 million as a result of the emergence from a cumulative loss position and positive evidence from forecasted pre-tax income from operations. The remaining valuation allowance in Malaysia is associated with net deferred tax assets of other tax ring-fences which lack sufficient positive evidence to support realizability. While we emerged from a recent cumulative loss position in the U.S. (non-Midstream) in 2023, the cumulative income position is near breakeven. Until we see a more significant and sustained pattern of objectively verifiable income, we do not assign significant weight to subjective long-term projections of future income and thus maintain a full valuation allowance against our U.S. (non-Midstream) federal and state deferred tax assets. If anticipated future earnings are exceeded, sufficient positive evidence may become available to support the release of valuation allowance in the future. This would result in the recognition of certain deferred tax assets on the balance sheet and a decrease to income tax expense for the period in which the release is recorded.
Asset Retirement Obligations: We have legal obligations to remove and dismantle long‑lived assets and to restore land or seabed at certain E&P locations. In accordance with generally accepted accounting principles, we recognize a liability for the fair value of required asset retirement obligations. In addition, the fair value of any legally required conditional asset retirement obligation is recorded if the liability can be reasonably estimated. We capitalize such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. We estimate the fair value of these obligations by discounting projected future payments that will be required to satisfy the obligations. In determining these estimates, we are required to make several assumptions and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors and discount rate. In addition, there are other external factors, which could significantly affect the ultimate settlement costs or timing for these obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs and foreign currency exchange rates and advances in technology. As a result, our estimates of asset retirement obligations are subject to revision due to the factors described above. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in our Statement of Consolidated Income. See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements.
Retirement Plans: We have funded non-contributory defined benefit pension plans, an unfunded supplemental pension plan and an unfunded postretirement medical plan. We recognize the net change in the funded status of the projected benefit obligation for these plans in the Consolidated Balance Sheet. The determination of the obligations and expenses related to these plans are based on several actuarial assumptions. These assumptions represent estimates made by us, some of which can be affected by external factors. The most significant assumptions relate to:
Discount rates used for measuring the present value of future plan obligations and net periodic benefit cost: The discount rates used to estimate our projected benefit obligations and net periodic benefit cost is based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations. At December 31, 2023, a 0.25% decrease in the discount rate assumptions would increase projected benefit obligations by approximately $65 million and would increase forecasted 2024 annual net periodic benefit expense by approximately $1 million. The increase in the projected benefit obligations would decrease the funded status of our pension plans, but any decrease in the funded status would be partially mitigated by increases in the fair value of fixed income investments in the asset portfolios.
Expected long-term rates of returns on plan assets: The expected rate of return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of plan assets to that asset category. The future expected rate of return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories. At December 31, 2023, a 0.25% decrease in the expected long-term rates of return on plan assets assumption would increase forecasted 2024 annual net periodic benefit expense by approximately $5 million.
Other assumptions include the rate of future increases in compensation levels and expected participant mortality.
Derivatives: We utilize derivative instruments, including futures, forwards, options and swaps, individually or in combination to mitigate our exposure to fluctuations in the prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates. All derivative instruments are recorded at fair value in our Consolidated Balance Sheet. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of Other Comprehensive Income (Loss). Amounts included in Accumulated Other Comprehensive Income (Loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged item is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for financial assets, and our credit is considered for financial liabilities.
We also record certain nonfinancial assets and liabilities at fair value when required by generally accepted accounting principles. These fair value measurements are recorded in connection with business combinations, qualifying non-monetary exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments or goodwill.
We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level assigned to a fair value measurement is based on the lowest significant input level within this fair value hierarchy.
Environment, Health and Safety
Our long-term vision and values provide a foundation for how we do business and define our commitment to meeting high standards of corporate citizenship and creating a long lasting positive impact on the communities where we do business. Our strategy is reflected in our EHS & SR policies and by a management system framework that helps protect our workforce, customers and local communities. Our management systems are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the short‑term, increase our operating costs and could also require increased capital expenditures to reduce potential risks to our assets, reputation and license to operate. In addition to enhanced EHS & SR performance, improved productivity and operational efficiencies may be realized from investments in EHS & SR. We have programs in place to evaluate regulatory compliance, audit facilities, train employees, prevent and manage risks and emergencies and to generally meet corporate EHS & SR goals and objectives.
Environmental Matters
We recognize that climate change is a global environmental concern. We assess, monitor and take measures to reduce our carbon footprint at existing and planned operations. The EPA has adopted a series of GHG monitoring, reporting, and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting further legislation to reduce GHG emissions. For example, in December 2023, the EPA issued a final rule to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. In addition, the IRA includes a methane emissions reduction program for petroleum and natural gas systems, which requires the EPA to impose a “waste emissions charge” on excess methane emissions from certain natural gas and oil sources that are required to report under EPA’s Greenhouse Gas Reporting Program beginning January 1, 2024 and also provides significant funding and incentives for research and development of competing low carbon energy production methods. In January of 2024, the EPA released its proposed rule to implement the methane emissions fee with a proposed effective date in 2025 for reporting 2024 emissions. Furthermore, states have taken measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. At the
international level, the Paris Agreement on climate change aimed to enhance global response to global temperature changes and to reduce GHG emissions, among other things. We are committed to complying with all GHG emissions regulations that apply to our operations, including those related to venting or flaring of natural gas, and the responsible management of GHG emissions at our facilities. While we monitor climate-related regulatory initiatives and international public policy issues, the current state of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs, or related measures to encourage use of low carbon energy could result in higher capital expenditures and operating expenses for us and the oil and gas industry in general and may reduce demand for our products, as described under Regulatory, Legal and Environmental Risks in Part 1, Item 1A. Risk Factors.
We will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be necessary include E&P facilities, sites from discontinued operations where we retained liability and, although not currently significant, EPA “Superfund” sites where we have been named a potentially responsible party. We accrue for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. For additional information, see Item 3. Legal Proceedings. At December 31, 2023, our reserve for estimated remediation liabilities was approximately $50 million. We expect that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. Our remediation spending was approximately $28 million in 2023 (2022: $23 million; 2021: $16 million). The amount of other expenditures incurred to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses.
As an element of our EHS and SR strategy, we purchase carbon credits annually to offset 100 percent of our estimated Scope 3 business travel emissions and 100 percent of our estimated Scope 1 and Scope 3 emissions associated with operating the Corporation’s truck fleet, aviation activities (aircraft and helicopters) and personal and rental vehicle miles driven on company business. We also offset purchased electricity used in our operations from nonrenewable sources by purchasing renewable energy certificates. The cost of these purchased and retired renewable energy certificates was not material to our financial results in 2023 and are included in Operating costs and expenses in the Statement of Consolidated Income.
In December 2022, we announced an agreement with the Government of Guyana to purchase 37.5 million REDD+ carbon credits, including current and future issuances, for a minimum of $750 million from 2022 through 2032 to prevent deforestation and support sustainable development in Guyana. These credits will be on the ART Registry and will be independently verified to represent permanent and additional emissions reductions under ART’s REDD+ Environmental Standard 2.0 (TREES). This agreement adds to the Corporation’s ongoing emissions reduction efforts and is an important part of our commitment to achieve net zero Scope 1 and 2 greenhouse gas emissions on a net equity basis by 2050. As of December 31, 2023, we have purchased 10 million REDD+ carbon credits registered on the ART Registry for $150 million under this agreement, which is included in non-current Other assets in the Consolidated Balance Sheet.
Health and Safety Matters
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels regarding the health and safety of E&P operations. Such laws and regulations relate to, among other matters, occupational safety, the use of hydraulic fracturing to stimulate crude oil and natural gas production, well control and integrity, process safety and equipment integrity, and may include permitting and disclosure requirements, operating restrictions and other conditions on the development of crude oil and natural gas. The level of our expenditures to comply with federal, state, local and foreign country health and safety regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. While compliance with laws and regulations relating to health and safety matters increases the overall cost of business for us and the oil and gas industry in general, it has not had, to date, a material adverse effect on our operations, financial condition or results of operations.
Occupational Safety: We are subject to the requirements set forth under federal workplace standards by the OSHA and comparable state statutes that regulate the protection of the health and safety of workers. Under OSHA and other federal and state occupational safety and health laws and laws of foreign countries in which we operate, we must develop, maintain and disclose certain information about hazardous materials used, released, or produced in our operations.
Production and Well Integrity: Our U.S. onshore production facilities are subject to U.S. federal government, state and local regulations regarding the use of hydraulic fracturing and well control and integrity. Our offshore production facilities in the Gulf of Mexico are subject to the U.S. federal government’s Safety and Environmental Management System regulations, which provide a systematic approach for identifying, managing and mitigating hazards. Adapting to new technical standards and procedures in production and in our well integrity management system is fundamental to our aim of protecting the environment as well as the health and safety of our workforce and the communities in which we operate, and to safeguarding our product.
Process Safety and Equipment Integrity: We are also regulated at federal, state, local and foreign government levels regarding process safety and the integrity of our equipment, including OSHA’s Process Safety Management of Highly Hazardous Chemicals standard. ICE are barriers and safeguards that prevent or mitigate process safety incidents through detection, isolation, containment, control or emergency preparedness and response within our facilities. We have established ICE performance standards, which set
specific requirements and criteria for inspections and tests that help to ensure ICE barriers are effective. We conduct assessments collaboratively with our operated assets, subject matter experts and technical authorities to evaluate compliance with corporate and asset environment, health and safety standards and procedures, as well as with applicable regulations. For additional information on our emergency response and incident mitigation activities, see Emergency Preparedness and Response Plans and Procedures in Items 1 and 2. Business and Properties.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil, NGL, and natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, financial risk management activities refer to the mitigation of these risks through hedging activities.
Controls: We maintain a control environment under the direction of our Chief Risk Officer. Controls over instruments used in financial risk management activities include volumetric and term limits. Our Treasury department is responsible for administering and monitoring foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors.
Instruments: We primarily use forward commodity contracts, foreign exchange forward contracts, futures, swaps, and options in our risk management activities. These contracts are generally widely traded instruments with standardized terms. The following describes these instruments and how we use them:
•Swaps: We use financially settled swap contracts with third parties as part of our financial risk management activities. Cash flows from swap contracts are determined based on underlying commodity prices, interest rates or foreign exchange rates and are typically settled over the life of the contract.
•Forward Foreign Exchange Contracts: We enter into forward contracts, primarily for the British Pound and Malaysian Ringgit, which commit us to buy or sell a fixed amount of those currencies at a predetermined exchange rate on a future date.
•Exchange-traded Contracts: We may use exchange-traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.
•Options: Options on various underlying energy commodities include exchange-traded and third-party contracts and have various exercise periods. As a purchaser of options, we pay a premium at the outset and are exposed to the favorable consequence of collecting payment upon exercise depending upon the underlying commodity price movement. As a seller of options, we receive a premium at the outset and are exposed to the unfavorable consequence of having to make payment upon exercise depending upon the underlying commodity price movement.
Financial Risk Management Activities
We have outstanding foreign exchange contracts with notional amounts totaling $226 million at December 31, 2023 that are used to reduce our exposure to fluctuating foreign exchange rates for various currencies. The change in fair value of foreign exchange contracts from a 10% strengthening or weakening in the U.S. Dollar exchange rate is estimated to be a gain of approximately $20 million or a loss of approximately $25 million at December 31, 2023.
At December 31, 2023, our total long-term debt, which was substantially comprised of fixed-rate instruments, had a carrying value of $8,613 million and a fair value of $9,006 million. A 15% increase or decrease in interest rates would decrease or increase the fair value of debt by approximately $400 million or $440 million, respectively. Any changes in interest rates do not impact our cash outflows associated with fixed-rate interest payments or settlement of debt principal, unless a debt instrument is repurchased prior to maturity.
See Note 19, Financial Risk Management Activities in the Notes to Consolidated Financial Statements for further details.
Item 8. Financial Statements and Supplementary Data
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Schedules have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial statements or the notes thereto.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a‑15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes‑Oxley Act, based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2023.
The Corporation’s independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2023, as stated in their report, which is included herein.
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| By | | /s/ John P. Rielly | | By | | /s/ John B. Hess |
| | | John P. Rielly
Executive Vice President and
Chief Financial Officer | | | | John B. Hess
Chief Executive Officer |
February 26, 2024
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Hess Corporation
Opinion on Internal Control Over Financial Reporting
We have audited Hess Corporation and consolidated subsidiaries’ internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Hess Corporation and consolidated subsidiaries (the Corporation) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Corporation as of December 31, 2023 and 2022, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2023, and the related notes and our report dated February 26, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/
February 26, 2024
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Hess Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Hess Corporation and consolidated subsidiaries (the Corporation) as of December 31, 2023 and 2022, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Corporation at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 26, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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| | Depreciation, depletion and amortization of proved oil and natural gas properties |
Description of the
Matter
| | The net book value of the Corporation’s exploration and production assets was $14,196 million at December 31, 2023, and depreciation, depletion and amortization (DD&A) expense was $1,852 million for the year then ended. As described in Note 1 to the consolidated financial statements, the Corporation follows the successful efforts method of accounting for its oil and gas exploration and production activities. Under this method, capitalized costs to acquire oil and natural gas properties are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Proved oil and gas reserves are prepared using standard geological and engineering methods generally recognized in the petroleum industry based on evaluations of estimated in-place hydrocarbon volumes using financial and non-financial inputs. Significant judgment is required by the Corporation’s internal engineering staff in interpreting the data used to estimate reserves. Estimating proved reserves also requires the selection and evaluation of inputs, including historical production, oil and natural gas price assumptions as well as future operating and capital costs assumptions, among others. Management used independent petroleum engineering specialists to audit approximately 89% of the Corporation’s proved reserves at December 31, 2023 as prepared by the Corporation’s internal engineering staff. |
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| | Auditing the Corporation's DD&A expense calculation is especially complex because of the use of the work of the Corporation's internal engineering staff and the independent petroleum engineering specialists and the evaluation of management's determination of the inputs described above used by these engineering specialists in estimating proved oil and gas reserves.
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| How We Addressed the Matter in Our Audit | | We obtained an understanding, evaluated the design and tested the operating effectiveness of internal controls that address the risks of material misstatement relating to the DD&A expense calculation. This included controls over the completeness and accuracy of the financial data used in estimating proved oil and gas reserves.
Our testing of the Corporation’s DD&A expense calculation included, among other procedures, evaluating the professional qualifications and objectivity of the Corporation’s internal petroleum engineering specialist responsible for overseeing the preparation of the Corporation’s reserve estimates and of the independent petroleum engineering specialist used to audit the estimates. On a sample basis, we tested the completeness and accuracy of the financial data used in the estimation of proved oil and gas reserves by agreeing significant inputs to source documentation, where available, and assessing the inputs for reasonableness based on review of corroborative evidence and consideration of any contrary evidence. Additionally, we performed analytic and lookback procedures on select inputs into the oil and gas reserve estimate as well as on the outputs. Finally, we tested that the DD&A expense calculations are based on the appropriate proved oil and gas reserve balances from the Corporation’s reserve report. |
/s/
We have served as the Corporation’s auditor since 1971
February 26, 2024
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
| | | | | | | | | | | |
| | December 31, |
| | 2023 | | 2022 |
| | | |
| (In millions,
except share amounts) |
| Assets | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | | | | $ | | |
| Accounts receivable: | | | |
| From contracts with customers | | | | | |
| Joint venture and other | | | | | |
| Inventories | | | | | |
| Other current assets | | | | | |
| Total current assets | | | | | |
| Property, plant and equipment: | | | |
| Total — at cost | | | | | |
| Less: Reserves for depreciation, depletion, amortization and lease impairment | | | | | |
| Property, plant and equipment — net | | | | | |
| Operating lease right-of-use assets — net | | | | | |
| Finance lease right-of-use assets — net | | | | | |
| Goodwill | | | | | |
| Deferred income taxes | | | | | |
| Post-retirement benefit assets | | | | | |
| Other assets | | | | | |
| Total Assets | $ | | | | $ | | |
| Liabilities | | | |
| Current Liabilities: | | | |
| Accounts payable | $ | | | | $ | | |
| Accrued liabilities | | | | | |
| Taxes payable | | | | | |
| Current portion of long-term debt | | | | | |
| Current portion of operating and finance lease obligations | | | | | |
| Total current liabilities | | | | | |
| Long-term debt | | | | | |
| Long-term operating lease obligations | | | | | |
| Long-term finance lease obligations | | | | | |
| Deferred income taxes | | | | | |
| Asset retirement obligations | | | | | |
| Other liabilities and deferred credits | | | | | |
| Total Liabilities | | | | | |
| Equity | | | |
| Hess Corporation stockholders’ equity: | | | |
Common stock, par value $; Authorized — shares: | | | |
Issued — shares (2022: ) | | | | | |
| Capital in excess of par value | | | | | |
| Retained earnings | | | | | |
| Accumulated other comprehensive income (loss) | () | | | () | |
| Total Hess Corporation stockholders’ equity | | | | | |
| Noncontrolling interests | | | | | |
| Total equity | | | | | |
| Total Liabilities and Equity | $ | | | | $ | | |
The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production activities.
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED INCOME
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions, except per share amounts) |
| Revenues and Non-Operating Income | | | | | |
| Sales and other operating revenues | $ | | | | $ | | | | $ | | |
| Gains on asset sales, net | | | | | | | | |
| Other, net | | | | | | | | |
| Total revenues and non-operating income | | | | | | | | |
| | | | | |
| Costs and Expenses | | | | | |
| Marketing, including purchased oil and gas | | | | | | | | |
| Operating costs and expenses | | | | | | | | |
| Production and severance taxes | | | | | | | | |
| Exploration expenses, including dry holes and lease impairment | | | | | | | | |
| General and administrative expenses | | | | | | | | |
| Interest expense | | | | | | | | |
| Depreciation, depletion and amortization | | | | | | | | |
| Impairment and other | | | | | | | | |
| Total costs and expenses | | | | | | | | |
| Income Before Income Taxes | | | | | | | | |
| Provision for income taxes | | | | | | | | |
| Net Income | | | | | | | | |
| Less: Net income attributable to noncontrolling interests | | | | | | | | |
| Net Income Attributable to Hess Corporation | $ | | | | $ | | | | $ | | |
| | | | | |
| Net Income Attributable to Hess Corporation Per Common Share: | | | | | |
| Basic | $ | | | | $ | | | | $ | | |
| Diluted | $ | | | | $ | | | | $ | | |
| Weighted Average Number of Common Shares Outstanding: | | | | | |
| Basic | | | | | | | | |
| Diluted | | | | | | | | |
| Common Stock Dividends Per Share | $ | | | | $ | | | | $ | | |
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Net Income | $ | | | | $ | | | | $ | | |
| Other Comprehensive Income (Loss): | | | | | |
| Derivatives designated as cash flow hedges | | | | | |
| Effect of hedge (gains) losses reclassified to income | | | | | | | | |
| Income taxes on effect of hedge (gains) losses reclassified to income | | | | | | | | |
| Net effect of hedge (gains) losses reclassified to income | | | | | | | | |
| Change in fair value of cash flow hedges | () | | | () | | | () | |
| Income taxes on change in fair value of cash flow hedges | | | | | | | | |
| Net change in fair value of cash flow hedges | () | | | () | | | () | |
| Change in derivatives designated as cash flow hedges, after taxes | | | | | | | () | |
| Pension and other postretirement plans | | | | | |
| (Increase) reduction in unrecognized actuarial losses | () | | | | | | | |
| Income taxes on actuarial changes in plan liabilities | | | | () | | | | |
| (Increase) reduction in unrecognized actuarial losses, net | () | | | | | | | |
| Amortization of net actuarial losses | | | | | | | | |
| Income taxes on amortization of net actuarial losses | () | | | () | | | | |
| Net effect of amortization of net actuarial losses | | | | | | | | |
| Change in pension and other postretirement plans, after taxes | () | | | | | | | |
| Other Comprehensive Income (Loss) | () | | | | | | | |
| Comprehensive Income | | | | | | | | |
| Less: Comprehensive income attributable to noncontrolling interests | | | | | | | | |
| Comprehensive Income Attributable to Hess Corporation | $ | | | | $ | | | | $ | | |
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| | | | | |
| | (In millions) |
| Cash Flows From Operating Activities | | | | | |
| Net income | $ | | | | $ | | | | $ | | |
| Adjustments to reconcile net income to net cash provided by (used in) operating activities: | | | | | |
| (Gains) on asset sales, net | () | | | () | | | () | |
| Depreciation, depletion and amortization | | | | | | | | |
| Impairment and other | | | | | | | | |
| Exploratory dry hole costs | | | | | | | | |
| Exploration lease impairment | | | | | | | | |
| Pension settlement loss | | | | | | | | |
| Stock compensation expense | | | | | | | | |
| Noncash (gains) losses on commodity derivatives, net | | | | | | | | |
| Provision (benefit) for deferred income taxes and other tax accruals | | | | | | | | |
| Changes in operating assets and liabilities: | | | | | |
| (Increase) decrease in accounts receivable | () | | | () | | | () | |
| (Increase) decrease in inventories | () | | | | | | | |
| Increase (decrease) in accounts payable and accrued liabilities | | | | | | | | |
| Increase (decrease) in taxes payable | | | | () | | | | |
| Changes in other operating assets and liabilities | () | | | () | | | () | |
| Net cash provided by (used in) operating activities | | | | | | | | |
| | | | | |
| Cash Flows From Investing Activities | | | | | |
| Additions to property, plant and equipment – E&P | () | | | () | | | () | |
| Additions to property, plant and equipment – Midstream | () | | | () | | | () | |
|
| Proceeds from asset sales, net of cash sold | | | | | | | | |
| Other, net | () | | | () | | | () | |
| Net cash provided by (used in) investing activities | () | | | () | | | () | |
| | | | | |
| Cash Flows From Financing Activities | | | | | |
| Net borrowings (repayments) of debt with maturities of 90 days or less | | | | () | | | () | |
| Debt with maturities of greater than 90 days: | | | | | |
| Borrowings | | | | | | | | |
| Repayments | () | | | () | | | () | |
| Cash dividends paid | () | | | () | | | () | |
| Common stock acquired and retired | () | | | () | | | | |
| Proceeds from sale of Class A shares of Hess Midstream LP | | | | | | | | |
| Noncontrolling interests, net | () | | | () | | | () | |
| Employee stock options exercised | | | | | | | | |
| Payments on finance lease obligations | () | | | () | | | () | |
| Other, net | () | | | () | | | () | |
| Net cash provided by (used in) financing activities | () | | | () | | | () | |
| | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | () | | | () | | | | |
| Cash and Cash Equivalents at Beginning of Year | | | | | | | | |
| Cash and Cash Equivalents at End of Year | $ | | | | $ | | | | $ | | |
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED EQUITY
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Capital in Excess of Par | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total Hess Stockholders’ Equity | | Noncontrolling Interests | | Total Equity |
| | | | | | | | | | | | | |
| | |
| Balance at December 31, 2020 | $ | | | | $ | | | | $ | | | | $ | () | | | $ | | | | $ | | | | $ | | |
| Net income | — | | | — | | | | | | — | | | | | | | | | | |
| Other comprehensive income (loss) | — | | | — | | | — | | | | | | | | | — | | | | |
| Share-based compensation | | | | | | | — | | | — | | | | | | — | | | | |
| Dividends on common stock | — | | | — | | | () | | | — | | | () | | | — | | | () | |
| Sale of Class A shares of Hess Midstream LP | — | | | | | | — | | | — | | | | | | | | | | |
| Repurchase of Class B units of Hess Midstream Operations LP | — | | | | | | — | | | — | | | | | | () | | | () | |
| Noncontrolling interests, net | — | | | — | | | — | | | — | | | — | | | () | | | () | |
| Balance at December 31, 2021 | $ | | | | $ | | | | $ | | | | $ | () | | | $ | | | | $ | | | | $ | | |
| Net income | — | | | — | | | | | | — | | | | | | | | | | |
| Other comprehensive income (loss) | — | | | — | | | — | | | | | | | | | — | | | | |
| Share-based compensation | | | | | | | — | | | — | | | | | | — | | | | |
| Dividends on common stock | — | | | — | | | () | | | — | | | () | | | — | | | () | |
| Sale of Class A shares of Hess Midstream LP | — | | | | | | — | | | — | | | | | | | | | | |
| Repurchase of Class B units of Hess Midstream Operations LP | — | | | | | | — | | | — | | | | | | () | | | () | |
| Common stock acquired and retired | () | | | () | | | () | | | — | | | () | | | — | | | () | |
| Noncontrolling interests, net | — | | | — | | | — | | | — | | | — | | | () | | | () | |
| Balance at December 31, 2022 | $ | | | | $ | | | | $ | | | | $ | () | | | $ | | | | $ | | | | $ | | |
| Net income | — | | | — | | | | | | — | | | | | | | | | | |
| Other comprehensive income (loss) | — | | | — | | | — | | | () | | | () | | | — | | | () | |
| Share-based compensation | | | | | | | — | | | — | | | | | | — | | | | |
| Dividends on common stock | — | | | — | | | () | | | — | | | () | | | — | | | () | |
| Sale of Class A shares of Hess Midstream LP | — | | | | | | — | | | — | | | | | | | | | | |
| Repurchase of Class B units of Hess Midstream Operations LP | — | | | | | | — | | | — | | | | | | () | | | () | |
| Noncontrolling interests, net | — | | | — | | | — | | | — | | | — | | | () | | | () | |
| Balance at December 31, 2023 | $ | | | | $ | | | | $ | | | | $ | () | | | $ | | | | $ | | | | $ | | |
See accompanying Notes to Consolidated Financial Statements.
% consolidated ownership interest in Hess Midstream LP at December 31, 2023 (see Note 4, Hess Midstream LP) provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.On October 22, 2023, we entered into an Agreement and Plan of Merger (the Merger Agreement) with Chevron Corporation (Chevron) and Yankee Merger Sub Inc. (Merger Subsidiary), a direct, wholly-owned subsidiary of Chevron. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Subsidiary will be merged with and into Hess, and Hess will be the surviving corporation in the Merger as a direct, wholly-owned subsidiary of Chevron (such transaction, the Merger). Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of shares of Chevron common stock for each share of our common stock. The transaction is expected to close mid-2024, subject to shareholder and regulatory approvals and other closing conditions.
% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. Our undivided interests in unincorporated oil and gas E&P ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method.
. Contracts with customers for the sale of international crude oil involve the short-term sale of volumes during a specified period. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials, shortly after control of the volumes transfers to the customer. International contracts with customers for the sale of natural gas are in the form of natural gas sales agreements with government entities that have durations that are aligned with the durations of production sharing contracts or other contractual arrangements with host governments. Pricing for our natural gas sales agreements in North Malay Basin and Block A-18 of JDA are determined using contractual formulas that are based on the price of alternative fuels as obtained from price indices and other factors.
Contract Balances:
Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights. Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGL, or natural gas. At December 31, 2023, there were contract liabilities. At December 31, 2022, there were contract liabilities of $ million resulting from a take-or-pay deficiency payment received in 2021 that was subject to a make-up period expiring in December 2023. During the year ended December 31, 2023, revenue of $ million was recognized within Sales and other operating revenues that was included in the contract liability balance at December 31, 2022. At December 31, 2023 and 2022, there were contract assets.
Transaction Price Allocated to Remaining Performance Obligations:
The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is variable. Further, many of our contracts with customers have durations of less than twelve months. Accordingly, we have elected under the provisions of Accounting Standards Codification (ASC) 606, Revenues from Contracts with Customers, the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.
Sales-based Taxes:
We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.
Revenue from Non-customers:
In Guyana, the joint venture partners (Co-Venturers) to the Stabroek Block petroleum agreement are subject to the income tax laws of Guyana and remain primarily liable for income taxes due on the results of operations, resulting in recognition of income tax expense. Pursuant to the contractual arrangements of the petroleum agreement, a portion of gross production from the block, separate from the Co-Venturers’ cost oil and profit oil entitlement, is used to satisfy the Co-Venturers’ income tax liability. This portion of gross production, referred to as tax barrels, is included in our reported production volumes and is recognized as sales revenue from non-customers.
Midstream
The Midstream segment earns substantially all of its revenues by charging fees for gathering, compressing and processing natural gas and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane; and gathering and disposing produced water. Effective January 1, 2014, certain subsidiaries of Hess Midstream LP entered into (i) gas gathering, (ii) crude oil gathering, (iii) gas processing and fractionation, (iv) storage services and (v) terminaling and export services commercial agreements with certain subsidiaries of Hess, each generally with an initial ten-year term which could be extended for an additional ten-year term at the unilateral right of the Hess Midstream LP subsidiaries. These Hess Midstream LP subsidiaries exercised their right to extend the terms of the gas gathering, crude oil gathering, gas processing and fractionation, storage services, and terminaling and export services commercial agreements for the secondary term effective January 1, 2024 through December 31, 2033. Effective January 1, 2019, a subsidiary of Hess Midstream LP entered into water gathering and disposal services agreements
% of the nominations and apply on a -year rolling basis such that they are set for the following the most recent nomination. As the minimum volume commitments are subject to fluctuation, and these commercial agreements contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price is variable at inception of each of the commercial agreements. The Midstream segment has elected the practical expedient under the provisions of Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. If the volumes delivered are less than the applicable minimum volume commitments under the commercial agreements during any quarter, the applicable Hess subsidiary is obligated to pay a shortfall fee equal to the volume deficiency multiplied by the related gathering, processing and/or terminaling fee. The Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represents a separate, distinct performance obligation. During the initial term of each commercial agreement, volume deficiencies are measured quarterly and recognized as revenue in the same period, as any associated shortfall payments are not subject to future reduction or offset. During the secondary term of each commercial agreement, the applicable Hess subsidiary will be entitled to receive a credit, calculated in barrels or Mcf, as applicable, with respect to the amount of any shortfall fee paid. Such Hess subsidiary may apply the credit against the fees payable for any volumes delivered under the applicable agreement in excess of the nominated volumes up to four quarters after the credit is earned. Unused credits will be recognized as revenue when it becomes remote that such credits will be utilized. No credits will be provided with respect to crude oil terminaling services under the terminaling and export services commercial agreement or water handling services under the water gathering and disposal services agreements.
All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess subsidiaries that are the counterparty to the commercial agreements are eliminated upon consolidation.
million relates to the Midstream operating segment.
million. Environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment are capitalized.
million REDD+ carbon credits (2022: $ million, 2021: $) under a long-term agreement with the Government of Guyana that was executed in December 2022 in order to support ongoing carbon emissions reduction efforts by the Corporation. The carbon credits acquired by us are registered on the ART Registry, an over-the-counter registry, and can be sold to third parties or retired to offset emissions. These amounts would have been expensed in the period of purchase, instead of capitalized as indefinite-lived intangible assets, if the prohibition per the tentative decision above were applied. At December 31, 2023, the carrying value of our carbon credits of
million (2022: $ million) is included in non-current Other assets in the Consolidated Balance Sheet. All renewable energy certificates were retired and expensed in the period of purchase..
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